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, 2025

or

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

For The Transition Period from ____ to ____

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

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

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

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, 2025
American Electric Power Company, Inc.	534,794,763
	($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, 2025
		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
	Condensed Consolidated Financial Statements	40
AEP Texas Inc. and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	46
	Condensed Consolidated Financial Statements	49
AEP Transmission Company, LLC and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	55
	Condensed Consolidated Financial Statements	57
Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	62
	Condensed Consolidated Financial Statements	65
Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	71
	Condensed Consolidated Financial Statements	75
Ohio Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	81
	Condensed Consolidated Financial Statements	84
Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations	89
	Condensed Financial Statements	92
Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations	98
	Condensed Consolidated Financial Statements	101
Index of Condensed Notes to Condensed Financial Statements of Registrants		107
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			195
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., 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 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 Equity Funds Used During Construction.
ALJ	Administrative Law Judge.
AOCI	Accumulated Other Comprehensive Income.
APCo	Appalachian Power Company, an AEP electric utility subsidiary. APCo engages in the generation, transmission and distribution of electric power to retail customers in the southwestern portion of Virginia and southern West Virginia.
Appalachian Consumer Rate Relief Funding	Appalachian Consumer Rate Relief Funding, LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
APSC	Arkansas Public Service Commission.
ARO	Asset Retirement Obligations.
ASU	Accounting Standards Update.
ATM	At-the-Market.
CAA	Clean Air Act.
CAMT	Corporate Alternative Minimum Tax.
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.

i

Term	Meaning
CSAPR	Cross-State Air Pollution Rule.
CWIP	Construction Work in Progress.
DCC Fuel	DCC Fuel XV, DCC Fuel XVI, DCC Fuel XVII, DCC Fuel XVIII, DCC Fuel XIX, DCC Fuel XX and DCC XXI consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC	Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. DHLC is a non-consolidated VIE of SWEPCo.
Diversion	Diversion, acquired in December 2024, consists of 201 MWs of wind generation in Texas.
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.
ESA	Electric Service Agreement.
ESP	Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
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.
G&M	Generation & Marketing.
I&M	Indiana Michigan Power Company, an AEP electric utility subsidiary. I&M engages in the generation, transmission and distribution of electric power to retail customers in northern and eastern Indiana and southwestern Michigan.
IMTCo	AEP Indiana Michigan Transmission Company, Inc.
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.

ii

Term	Meaning
KWh	Kilowatt-hour.
LPSC	Louisiana Public Service Commission.
MATS	Mercury and Air Toxic Standards.
Midwest Transmission Holdings	Midwest Transmission Holdings, LLC, a subsidiary of AEPTCo Parent that owns all of the issued and outstanding stock of IMTCo and OHTCo.
MISO	Midcontinent Independent System Operator.
Mitchell Plant	A two unit, 1,560 MW coal-fired power plant located in Moundsville, West Virginia. The plant is jointly owned by KPCo and WPCo.
MMBtu	Million British Thermal Units.
MPSC	Michigan Public Service Commission.
MTM	Mark-to-Market.
MW	Megawatt.
MWh	Megawatt-hour.
NAAQS	National Ambient Air Quality Standards.
NCWF	North Central Wind Energy Facilities, a joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,484 MWs of wind generation.
NMRD	New Mexico Renewable Development, LLC.
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.
OPCo	Ohio Power Company, an AEP electric utility subsidiary. OPCo engages in the transmission and distribution of electric power to retail customers in Ohio.
OPEB	Other Postretirement Benefits.
OTC	Over-the-counter.
OVEC	Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent	American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
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.

iii

Term	Meaning
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 seven wholly-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP’s existing utility operating companies.
Storm Recovery Funding	SWEPCo Storm Recovery Funding, LLC, a wholly-owned subsidiary of SWEPCo and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Louisiana.
SWEPCo	Southwestern Electric Power Company, an AEP electric utility subsidiary. SWEPCo engages in the generation, transmission and distribution of electric power to retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas.
SWTCo	AEP Southwestern Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
TA	Transmission Agreement, effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
Tax Reform	On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
T&D	Transmission and Distribution Utilities.
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.
Turk Plant	John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
UPA	Unit Power Agreement.
Utility Money Pool	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
Valley Link	Valley Link Transmission Company, LLC, a holding company formed by Transource Energy, affiliates of Dominion Energy and FirstEnergy in 2024.
VIE	Variable Interest Entity.
Virginia SCC	Virginia State Corporation Commission.
VIU	Vertically Integrated Utilities.

iv

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

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 service territories.

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

• Inflationary or deflationary interest rate trends.

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

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

• The availability and cost of funds to finance working capital and capital needs, particularly (a) if expected sources of capital such as proceeds from the sale of assets, subsidiaries and 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 for interconnection.

• 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, wildfires and drought conditions that pose significant risks including potential litigation and the inability to recover significant damages and restoration costs incurred.

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

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

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

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

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

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

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

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

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

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

vi

• 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 at wholesale.

• Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.

• 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 artificial intelligence by us, our customers and our third party vendors and evolving expectations related to environmental, social and governance concerns.

• Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP.

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

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

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

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

• Other risks and unforeseen events, including wars and military conflicts, the effects of terrorism (including increased security costs), embargoes, cybersecurity threats, 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.

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, 2024 (the “2024 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 2025 Compared to Second Quarter of 2024

Earnings Attributable to AEP Common Shareholders increased from $340 million in 2024 to $1.2 billion in 2025 primarily due to:

•The favorable impact from the receipt of a June 2025 FERC order related to the treatment of NOLCs in transmission formula rates. See “June 2025 FERC Orders on NOLCs in Transmission Formula Rates” section below for additional information.

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

•An increase in operating expenses recorded in 2024 due to the Federal EPA’s revised CCR rule finalized in 2024.

•An increase in operating expenses recorded in 2024 due to the voluntary severance program that occurred in the second quarter of 2024.

•Favorable rate proceedings in AEP’s various jurisdictions.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

Earnings Attributable to AEP Common Shareholders increased from $1.3 billion in 2024 to $2.0 billion in 2025 primarily due to:

•The favorable impact from the receipt of a June 2025 FERC order related to the treatment of NOLCs in transmission formula rates. See “June 2025 FERC Orders on NOLCs in Transmission Formula Rates” section below for additional information.

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

•An increase in operating expenses recorded in 2024 due to the Federal EPA’s revised CCR rule finalized in 2024.

•An increase in operating expenses recorded in 2024 due to the voluntary severance program that occurred in the second quarter of 2024.

•An increase in sales volumes driven by favorable weather.

•Favorable rate proceedings in AEP’s various jurisdictions.

These increases were partially offset by:

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

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

1

Non-GAAP Financial Measures

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

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

Reconciliation of Reported GAAP Earnings to Operating Earnings

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

	Three Months Ended June 30, 2025
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Reported GAAP Earnings	$	1,225.8	$	121.1	$	555.8	$	106.9	$	124.1	$	102.8	$	63.7	$	115.6
Adjustments to Reported GAAP Earnings (a):
Mark-to-Market Impact of Commodity Hedging Activities (b)	20.0		—		—		—		(9.6)		—		—		—
FERC NOLC Order (c)	(480.1)		—		(353.9)		(28.9)		(35.6)		0.2		(4.0)		(54.1)
Total Specified Items	(460.1)		—		(353.9)		(28.9)		(45.2)		0.2		(4.0)		(54.1)
Operating Earnings	$	765.7	$	121.1	$	201.9	$	78.0	$	78.9	$	103.0	$	59.7	$	61.5

	Three Months Ended June 30, 2024
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Reported GAAP Earnings (Loss)	$	340.3	$	128.4	$	175.7	$	58.3	$	35.2	$	18.4	$	36.3	$	(70.1)
Adjustments to Reported GAAP Earnings (Loss) (a):
Mark-to-Market Impact of Commodity Hedging Activities (b)	(7.2)		—		—		—		(3.5)		—		—		—
Remeasurement of Excess ADIT Regulatory Liability (d)	(12.2)		—		—		—		(12.3)		—		—		—
Provision for Refund - Turk Plant (e)	126.4		—		—		—		—		—		—		126.4
Pending Sale of AEP OnSite Partners (f)	10.4		—		—		—		—		—		—		—
Severance Charges (g)	93.6		15.6		8.2		20.3		11.1		11.6		7.7		12.7
Federal EPA Coal Combustion Residuals Rule (h)	110.7		—		—		—		10.6		41.3		(4.0)		—
Total Specified Items	321.7		15.6		8.2		20.3		5.9		52.9		3.7		139.1
Operating Earnings	$	662.0	$	144.0	$	183.9	$	78.6	$	41.1	$	71.3	$	40.0	$	69.0

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

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

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

(d)Represents the impact of the remeasurement of Excess ADIT in Michigan.

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

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

(g)Represents employee severance charges.

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

2

	Six Months Ended June 30, 2025
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Reported GAAP Earnings	$	2,026.0	$	222.7	$	767.3	$	271.5	$	181.6	$	165.8	$	91.2	$	164.1
Adjustments to Reported GAAP Earnings (a):
Mark-to-Market Impact of Commodity Hedging Activities (b)	6.0		—		—		—		16.2		—		—		—
Sale of AEP OnSite Partners (c)	9.4		—		—		—		—		—		—		—
Impact of Ohio Legislation (d)	27.7		—		—		—		—		27.7		—		—
FERC NOLC Order (e)	(480.1)		—		(353.9)		(28.9)		(35.6)		0.2		(4.0)		(54.1)
Total Specified Items	(437.0)		—		(353.9)		(28.9)		(19.4)		27.9		(4.0)		(54.1)
Operating Earnings	$	1,589.0	$	222.7	$	413.4	$	242.6	$	162.2	$	193.7	$	87.2	$	110.0

	Six Months Ended June 30, 2024
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Reported GAAP Earnings	$	1,343.4	$	208.1	$	356.9	$	194.8	$	180.2	$	89.0	$	108.3	$	138.0
Adjustments to Reported GAAP Earnings (a):
Mark-to-Market Impact of Commodity Hedging Activities (b)	(59.0)		—		—		—		17.0		—		—		—
Remeasurement of Excess ADIT Regulatory Liability (f)	(44.6)		—		—		—		(12.3)		—		—		(32.3)
Impact of NOLC on Retail Ratemaking (g)	(259.6)		—		—		—		(69.1)		—		(56.5)		(134.0)
Disallowance - Dolet Hills Power Station (h)	11.1		—		—		—		—		—		—		11.1
Provision for Refund - Turk Plant (i)	126.4		—		—		—		—		—		—		126.4
Pending Sale of AEP OnSite Partners (j)	10.4		—		—		—		—		—		—		—
Severance Charges (k)	93.6		15.6		8.2		20.3		11.1		11.6		7.7		12.7
Federal EPA Coal Combustion Residuals Rule (l)	110.7		—		—		—		10.6		41.3		—		—
Total Specified Items	(11.0)		15.6		8.2		20.3		(42.7)		52.9		(48.8)		(16.1)
Operating Earnings	$	1,332.4	$	223.7	$	365.1	$	215.1	$	137.5	$	141.9	$	59.5	$	121.9

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

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

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

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

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

(f)Represents the impact of the remeasurement of Excess ADIT in Arkansas and Michigan.

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

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

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

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

(k)Represents employee severance charges.

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

3

RECENT DEVELOPMENTS AND TRANSACTIONS

NOLCs in Transmission Formula Rates - June 2025 FERC Orders

In June 2025, the FERC issued two orders, partially reversing its January 2024 decisions on the basis of IRS PLRs accepted into the record, and concluding that the accelerated depreciation-related NOLC adjustments should be included in rate base and should also be included in the computation of Excess ADIT regulatory liabilities to be refunded to customers. As a result of the June 2025 FERC orders, the Registrants recognized revenues, with interest, attributable to accelerated depreciation-related NOLCs included in transmission formula rates for years 2021 through 2025 and reduced Excess ADIT regulatory liabilities. The impact of the orders resulted in a $499 million increase in Earnings Attributable to AEP Common Shareholders for the three and six months ended June 30, 2025. See the table below and the “FERC 2021 PJM and SPP Transmission Formula Rate Challenge” section of Note 4 for additional information.

Company	Increase (Decrease) in Pretax Income (a)		Decrease in Income Tax Expense (b)		Increase in Noncontrolling Interest (c)		Increase in Net Income
	(in millions)
APCo	$	8.0	$	21.4	$	—	$	29.4
I&M	16.8		27.8		—		44.6
PSO	(12.4)		15.6		—		3.2
SWEPCo	16.8		38.9		—		55.7
AEPTCo	214.3		203.2		(55.2)		362.3
Other (d)	(2.1)		5.9		—		3.8
AEP Total	$	241.4	$	312.8	$	(55.2)	$	499.0

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

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

(c)The noncontrolling interest relates to IMTCo and OHTCo. See “Noncontrolling Interest in OHTCo and IMTCo” section of Note 6 for additional information.

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

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 should also be included in the computation of Excess ADIT regulatory liabilities to be refunded to customers. Based on this conclusion, I&M, PSO and SWEPCo recognized regulatory assets related to revenue requirement amounts to be collected from customers, reduced Excess ADIT regulatory liabilities and recorded favorable impacts to net income in the first quarter of 2024 as shown in the table below:

Company	Increase in Pretax Income from the Recognition of Regulatory Assets		Reduction in Income Tax Expense (a)		Increase in Net Income
	(in millions)
I&M	$	20.2	$	49.5	$	69.7
PSO	12.1		44.7		56.8
SWEPCo	35.4		101.1		136.5
AEP Total	$	67.7	$	195.3	$	263.0

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

4

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

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

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

(b)Pending in 2024 West Virginia Base Rate Case.

(c)Awaiting receipt of jurisdiction specific IRS PLR.

(d)Pending in 2025 Arkansas Base Rate Case.

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, 2025, AEP has NOLC regulatory assets of $114 million on its balance sheet.

Noncontrolling Interest in OHTCo and IMTCo (Applies to AEP and AEPTCo)

In January 2025, AEP announced a partnership whereby nonaffiliated entities will acquire a 19.9% noncontrolling interest in OHTCo and IMTCo for $2.82 billion. The transaction closed in June 2025 and AEP received cash proceeds of approximately $2.78 billion, net of transaction costs. Net proceeds will be used to help finance AEP’s $54 billion capital plan for 2025-2029, announced in November 2024, driven by transmission and distribution infrastructure upgrades and new generation to support anticipated load growth. See “Noncontrolling Interest in OHTCo and IMTCo” section of Note 6 for additional information.

PSO New Generation Resources

In the second quarter of 2025, PSO expanded its generation portfolio by acquiring three power generation facilities, as listed below, for a total of $1.4 billion. See “Acquisitions” section of Note 6 for additional information.

Plant Name	Fuel Type	Location	Acquisition Date	Generating Capacity
				(in MWs)
Green Country	Natural Gas	Jenks, OK	June 2025	795
Pixley	Solar	Barber County, KS	May 2025	189
Flat Ridge IV	Wind	Kingman and Harper Counties, KS	June 2025	135
Total				1,119

Kentucky Securitization

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

5

New Legislation

Ohio Legislation

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

As a result of this legislation, in the first quarter of 2025, OPCo recorded a $35 million estimated reduction to its OVEC-related purchased power regulatory asset for deferred net costs that are no longer probable of future recovery. Management is unable to predict the future impact to net income, cash flows and financial condition arising from the future changes in OPCo’s rate setting mechanisms and the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and the market revenues OPCo receives from that purchased power.

Texas Legislation

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

The tracking mechanism permits a qualifying electric utility to defer all or a portion of costs associated with its eligible transmission and distribution capital investments, including depreciation expense and carrying costs, as a regulatory asset. The tracking mechanism is available through 2035 and is an alternative to the existing capital tracking mechanisms in Texas. Deferred costs will be recovered through interim rate updates over a period not to exceed 18 months and earn a return until recovered. As a result of the new legislation, AEP Texas deferred approximately $25 million of eligible costs through June 2025 as a regulatory asset. Investments included in the tracking mechanism and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate review before the PUCT. If any of these deferred costs are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

Oklahoma Legislation

Effective August 28, 2025, in accordance with Oklahoma Senate Bill 998 (SB 998), a public utility that elects to defer costs may defer up to 90% of all depreciation expenses and returns associated with qualifying electric plants to a regulatory asset, provided the utility has notified the OCC of its election to do so. SB 998 excludes deferral of depreciation expense related to transmission plant and/or new electric generating units. Deferred costs will be recovered through base rates over a 20-year period and earn a return until recovered. SB 998 also allows for expedited recovery of new gas plant investments. Although SB 998 is expected to be favorable, management does not expect it to have a material impact on 2025 net income, cash flows and financial condition.

Federal Tax Legislation

On July 4, 2025, President Trump signed H.R. 1 into law, commonly known as the One Big Beautiful Bill Act (OBBBA). Most notably for AEP, this budget reconciliation legislation modifies and accelerates the phase out of wind and solar PTCs and ITCs, adds new restrictions to guard against certain foreign ownership or influence with respect to otherwise credit-eligible projects and makes 100% bonus depreciation permanent for our non-regulated entities. With the exception of bonus depreciation, this legislation is prospective and has no material impact on the current period financial statements. Following enactment of the legislation, on July 7, 2025, the President issued an Executive Order directing the Department of Treasury to issue new and revised wind and solar tax credit guidance within 45 days, which could impose further practical limits on the development of wind and solar projects. In addition to this potential near term guidance, additional significant guidance from the Department of Treasury and the IRS is expected on the tax provisions included in the OBBBA. AEP will continue to monitor any issued guidance and evaluate the impact on future net income, cash flows and financial condition.

6

Forward Sale of Equity

In March 2025, AEP entered into separate forward sale agreements with non-affiliate forward purchasers relating to 22,549,020 shares of AEP’s common stock at an initial price of $102.00 per share, exclusive of an underwriting discount equal to $2.244 per share. Except in certain specified circumstances that would require physical share settlement, AEP may elect to settle the forward sale transaction by means of physical, cash or net share settlement. The timing of the settlement of the forward sale agreements is also at AEP’s discretion, and management currently expects settlement to occur on or prior to December 31, 2026. To the extent the forward sale agreements are physically settled, AEP will issue common stock to the forward purchasers and receive cash proceeds based on the applicable forward sale price on the settlement date as defined in the forward sale agreements. As of June 30, 2025, AEP expects approximately $2.25 billion of net cash proceeds from the full physical settlement of the forward sale agreements and management anticipates using any future proceeds for general corporate purposes, which may include capital contributions to utility subsidiaries, acquisitions or repayment of debt. The forward sale transactions will be classified as equity transactions because they are indexed to AEP’s common stock and physical settlement is within AEP’s control.

Valley Link Investment (Applies to AEP and Transource Energy)

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

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

Fuel Cell Agreement

In November 2024, AEP executed a purchase agreement to acquire 100 MWs of solid oxide fuel cells with an option to acquire up to one gigawatt in total by the end of 2025. AEP, through its subsidiaries, is offering data centers and other large customers this custom solution to support their growing energy needs while grid infrastructure enhancements are completed to accommodate demand. As of June 30, 2025, OPCo has signed two contracts totaling approximately 98 MW for electricity service from fuel cells. In February 2025, OPCo requested PUCO approval of those two contracts. The PUCO approved the contracts in May 2025.

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

7

Customer Demand

AEP uses sales volumes by customer class as a way to measure significant drivers of customer demand. The percentage change in sales volumes by customer class are shown in the table below. The increase in commercial sales volumes was primarily due to new data processor loads. The decline in industrial sales volumes is primarily due to the continuing impact of elevated interest rates and tariff-related headwinds. The year-to-date decline in weather-normalized residential sales volumes is primarily due to energy efficiency and continuing inflationary pressures.

(a)Percentage change for the three months ended June 30, 2025 as compared to the three months ended June 30, 2024.

(b)Percentage change for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024.

The table below summarizes AEP’s revised 2025 forecasted retail sales volumes as compared to the forecast presented in the 2024 10-K. The decline in forecasted 2025 sales volumes is primarily due to the continuing impact of elevated interest rates, tariff-related headwinds and slower than anticipated load ramps among certain large commercial customers.

(a)As presented in the 2024 AEP 10-K: Forecasted percentage change for the year ended December 31, 2025 compared to the year ended December 31, 2024.

(b)Revised: Forecasted percentage change for the year ended December 31, 2025 compared to the year ended December 31, 2024. The revised 2025 forecast reflects year-to-date actual results plus six months of forecasted values based on underlying economic and demographic trends.

8

Inflation, Tariffs on International Trade and Supply Chain Disruption

The Registrants have experienced certain supply chain constraints driven by several factors including international tensions and the ramifications of regional conflict, inflation, increased energy infrastructure construction to meet energy intensive customer demands, labor shortages in certain trades and shortages in the availability of certain raw materials. These supply chain constraints have not had a material impact on the Registrants’ net income, cash flows and financial condition, but have extended lead times for certain goods and services and have contributed to higher prices for fuel, materials, labor, equipment and other needed commodities.

The U.S. administration has taken executive action and proposed additional measures intended to alter the U.S. approach to international trade policy, the terms of certain existing bilateral or multi‐lateral trade agreements and trading arrangements with foreign countries. Such changes to U.S. international trade policy, and any retaliatory trade measures that foreign governments may take in response, including the imposition of tariffs, sanctions, export or import controls, or other measures that restrict international trade, or the threat of such actions, could result in additional increases in the cost of certain goods, services and cost of capital and further extend lead times.

Management has implemented risk mitigation strategies seeking to limit the impacts of these supply chain constraints. Forecasted load growth and tariffs on international trade may further impact supply chains in the future by increasing demand pressures for certain materials and services, thereby requiring additional risk mitigation strategies to be deployed.

A prolonged continuation or a further increase in the severity of inflationary pressure, heightened geopolitical disruptions and tariffs on international trade could result in additional supply chain disturbances. These events could lead to additional increases in the cost of certain goods, services and cost of capital and further extend lead times which could reduce future net income and cash flows and impact financial condition.

Large Load/Data Center Tariffs

Certain AEP utility subsidiaries have made rate filings with state commissions to establish new tariffs for data centers and other large load customers. These new tariffs are generally designed to extend the duration of ESAs, implement higher minimum demand charges and address changes in contract capacity and termination of service. The table below provides a summary of the status of these new data center and large load tariffs.

Jurisdiction	Large Load Tariff	Status	Customer Eligibility
Indiana	Industrial Power	Approved	New load of 150 MW or more/70 MW for individual site
Kentucky	Industrial General Service	Approved	New commercial or industrial load of 150 MW or more
Ohio	Data Center	Approved	New data center load of 25 MW or more
Virginia	Large Power Service	Pending	New load of 150 MW or more/100 MW for individual site
West Virginia	Large Capacity/Industrial Power	Approved	New load of 200 MW or more

In June 2025, Texas Senate Bill 6 (SB 6) became effective and was signed into law by the Governor of Texas. SB 6 establishes standards for connecting large load customers within ERCOT in a way that supports business development in Texas while minimizing the potential for stranded infrastructure costs. The new legislation provides authority and discretion to the PUCT to provide additional rulemaking related to implementing and enforcing its mandates.

New Generation to Support Reliability

The growth of AEP’s regulated generation portfolio reflects the company’s commitment to meet increasing customer demand for power while balancing cost and reliability.

Significant Approved Renewable Generation Filings

AEP has received regulatory approvals from various state regulatory commissions to acquire approximately 1,979 MWs of owned renewable generation facilities, totaling approximately $4.7 billion. The estimated cost of these facilities is included in the Budgeted Capital Expenditures disclosure included in the Financial Condition section below. In addition, AEP has received regulatory approvals for 637 MWs of renewable PPAs. The following table summarizes regulatory approvals received for active renewable projects as of June 30, 2025:

9

Company	Generation Type	Expected Commercial Operation	Owned/PPA	Generating Capacity (a)
				(in MWs)
APCo	Solar	2025-2027	PPA	184
APCo (a)	Wind	2025-2026	Owned	344
I&M	Solar	2026-2027	PPA	280
I&M	Solar	2027	Owned	469
I&M	Wind	2026	PPA	100
PSO (b)	Solar	2025-2026	Owned	150
PSO (b)	Wind	2025-2026	Owned	418
SWEPCo	Solar	2025	PPA	73
SWEPCo	Wind	2025	Owned	598
Total Approved Renewable Projects				2,616

(a)APCo has issued notice to proceed for the construction of all 344 MWs of wind capacity.

(b)PSO has issued notices to proceed for the construction of two wind facilities for a total capacity of 418 MWs. These facilities are part of the approved projects contemplated within PSO’s 568 MWs of total new renewable generation.

(c)The recently enacted OBBBA legislation is not expected to impact the qualification of federal tax incentives for these generation facilities.

Natural Gas Generation

In December 2024, SWEPCo filed an application for a Certificate of Convenience and Necessity (CCN) with the APSC, LPSC and PUCT for the 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 Power Plant. If approved, the projects will help SWEPCo address increasing SPP capacity requirements. SWEPCo estimates the combined capital cost of these projects is approximately $723 million and the projects would be placed in service between November 2027 and May 2028.

In February 2025, I&M entered into a PSA to acquire an 870 MW combined-cycle power generation facility located in Ohio. In April 2025, I&M submitted a FERC 203 application for the acquisition. If approved, the project will help I&M address increasing capacity and power needs. I&M expects to close on the transaction in the first quarter of 2026.

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	Projected In-Service Dates	Generating Capacity
			(in MWs)
PSO (a)	November 2023	2027/2028	1,500
I&M (b)	September 2024	2029	4,000
APCo (c)	May 2024	2028	1,100
APCo (d)	May 2025	2029	800
APCo (e)	May 2025	2029	300
Total Significant RFPs			7,700

(a)RFP is seeking 1,500 MW of SPP accredited capacity and associated energy through an all-source solicitation.

(b)RFP is seeking up to 4,000 MW (cumulatively) from intermittent (wind, solar), non-intermittent (dispatchable), and emerging technology resources.

(c)RFP is seeking wind, solar, stand-alone battery energy storage systems and Renewable Energy Certificates.

(d)RFP is seeking 800 MW of wind, solar, and/or co-located or stand-alone battery energy storage systems PSAs.

(e)RFP is seeking 300 MW of wind, solar, hydro, or geothermal PPAs.

10

Capacity Purchase Agreements

In addition to the generation projects discussed above, AEP enters into Capacity Purchase Agreements (CPA) to satisfy operating companies capacity reserve margins to serve customers. The following table includes CPA amounts under contract as of June 30, 2025, by year, for the five year period 2025-2029:

	I&M			PSO		SWEPCo
		Natural Gas	Wind	Natural Gas	Wind	Natural Gas	Wind
Delivery Start Year	(in MWs)
2025		—	—	760	27	150	91
2026		615	73	460	86	150	100
2027		777	—	410	86	300	100
2028		1,000	—	410	—	450	—
2029		1,000	—	410	—	450	—

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 table summarizes the Registrants’ pending base rate case proceedings. See Note 4 - Rate Matters for additional information.

			Annual
		Filing	Base Revenue		Requested
Company	Jurisdiction	Date	Increase Request		ROE
			(in millions)
APCo	West Virginia	November 2024	$	224.0	10.8%
SWEPCo	Arkansas	March 2025	114.0		10.9%
OPCo	Ohio	May 2025	97.4		10.9%

Other Significant Regulatory Matters

2025 West Virginia Securitization Filing

In March 2025, APCo and WPCo (the Companies) requested to finance, through the issuance of securitization bonds, approximately $2.4 billion of West Virginia jurisdictional undepreciated property balances and regulatory assets including: (a) $321 million of the Companies’ remaining combined unrecovered ENEC balance related to costs incurred through February 28, 2023, (b) $1.7 billion of undepreciated West Virginia jurisdictional plant balances as of December 31, 2022 for the Amos, Mitchell and Mountaineer Plants, (c) $237 million of environmental costs previously approved for recovery through a separate West Virginia surcharge and (d) $118 million of West Virginia jurisdictional major storm operation and maintenance costs deferred as of June 2024.

The Companies also proposed that the WVPSC consider approving the securitization of additional ENEC under-recovered costs, such as those costs approved in the 2024 ENEC case, as well as additional deferred West Virginia jurisdictional major storm operation and maintenance costs, such as those associated with Hurricane Helene and Winter Storms Blair, Harlow and Jett.

In May 2025, WVPSC staff recommended that the $321 million ENEC under-recovery and $118 million storm cost deferral be excluded from the securitization. Staff recommended that the $321 million ENEC under-recovery continue to be recovered through the current ENEC rates and the storm cost deferral be recovered without a carrying charge over five years through base rates to be implemented in August 2025. A hearing was held in July 2025 and an order is expected in the third quarter of 2025.

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2025 Virginia Securitization Legislation and Securitization Filing

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

In July 2025, APCo filed a request with the Virginia SCC to finance, through the issuance of securitization bonds, approximately $1.4 billion of Virginia jurisdictional undepreciated property balances and a major storm operation and maintenance regulatory asset deferral balance. This proposed securitization included: (a) $1.2 billion of undepreciated Virginia jurisdictional plant balances as of December 31, 2023 for the Amos and Mountaineer Plants and (b) $141 million of Virginia jurisdictional major storm other operation and maintenance expenses deferred during the 2024-2025 biennial period.

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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

In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow a CCR surface impoundment at the Gavin Power Station to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several assertions related to the CCR Rule (see “CCR Rule” section below for additional information), including an assertion that the closure of the 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have notified AEP they believe they are entitled to indemnification for any damages that may result from these claims, including any future enforcement or litigation resulting from any determinations of noncompliance by the Federal EPA with various aspects of the CCR Rule consistent with the Gavin Denial. The owners of the Gavin Power Station have also sought indemnification for landowner claims for property damage allegedly caused by modifications to the FAR. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. In January 2024, Gavin Power LLC also filed a complaint with the United States District Court for the Southern District of Ohio, alleging various violations of the Administrative Procedure Act and asserting that the Federal EPA, through its prior inaction, has waived and is estopped from raising certain objections raised in the Gavin Denial. Based on the information currently available, management does not believe a loss is probable and cannot determine a range of potential losses, if any, that is reasonably possible of occurring.

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 result from the current Presidential administration.

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.

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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, 2025, AEP owned generating capacity of approximately 24,400 MWs, of which approximately 10,700 MWs were coal-fired.   In April 2024, the Federal EPA announced four major new rules directed at fossil-fuel electric generation facilities. Management continues to evaluate the impacts of these rules on the plans for the future of AEP’s generating fleet, in particular, the economic feasibility of making the requisite environmental investments in AEP’s fossil generation fleet. AEP continues to refine the cost estimates of complying with these rules to identify the best alternative for ensuring compliance with all of the rules while meeting AEP’s obligations to provide reliable and affordable electricity.

The costs of complying with new rules may also change based on: (a) potential state rules that impose additional more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity, (g) policy changes implemented by the Presidential administration and (h) other factors. In 2025, the Federal EPA under the current Presidential administration has proposed to rescind some of those rules and is evaluating potential changes to others.

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 implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (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. Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

National Ambient Air Quality Standards

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

Areas with air quality that does not meet the new standard will be designated by the Federal EPA as “nonattainment,” which will trigger an obligation for states to revise their SIPs to include additional requirements, resulting in further emission reductions to ensure that the new standard will be met. Areas around some of AEP’s generating facilities may be deemed nonattainment, which may require those facilities to install additional pollution controls or to implement operational constraints. The nonattainment designations by the Federal EPA and the subsequent SIP revisions by the affected states will take some time to complete; therefore, management cannot reasonably estimate the impact 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 could require 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. In 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs. Petitions for review of the final rule revisions were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In early 2018, the Federal EPA announced plans to revisit aspects of the final rule raised by petitioners in petitions for administrative reconsideration, and the court granted the Federal EPA’s motion to hold the litigation in abeyance.

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

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withdraw the prior proposed rule, including the proposed partial disapproval of the Texas SIP revision, and instead has proposed to approve the Texas Regional Haze SIP.

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

In February 2023, the Federal EPA Administrator finalized the disapproval of interstate transport SIPs submitted by 19 states, including Texas, addressing the 2015 Ozone NAAQS. The Federal EPA disapproved interstate transport SIPs submitted by additional states soon thereafter. Disapproval of the SIPs provided the Federal EPA with authority to impose a FIP for those states, replacing the SIPs that were disapproved. In August 2023, a FIP (the Good Neighbor Plan) went into effect that further revised the ozone season NOX budgets under the existing CSAPR program in states to which the FIP applies. As a result of several separate legal challenges brought by states and industry parties in various federal courts, implementation of the FIP has been stayed in all of the states in which AEP operates. In October 2024, the Federal EPA issued a final rule to administratively stay the effectiveness of the Good Neighbor Plan’s requirements for all sources covered by that rule as promulgated where an administrative stay was not already in place. The administrative stay of the Good Neighbor Plan’s effectiveness for power plants and other industrial facilities in each of the 23 states will remain in place until the Supreme Court lifts its order staying enforcement of the Good Neighbor Plan, other courts lift any judicial orders staying the SIP disapproval action as to the state, and the Federal EPA takes subsequent rulemaking action consistent with any judicial rulings on the merits. Additionally, in February 2025, the Federal EPA filed a motion with the court seeking to hold the legal challenges related to the Good Neighbor Plan in abeyance for 60 days, to allow the new administration time to review the rule. In March 2025, the Federal EPA filed a motion for the Good Neighbor Plan to remand the rule while leaving it in effect, indicating that the Federal EPA has identified issues with the rule that make reconsideration of issues, including issues raised in the litigation, appropriate. In April 2025, the D.C. Circuit Court of Appeals removed the cases challenging the Good Neighbor Plan from the oral argument calendar and placed the cases in abeyance pending further order of the court, with status reports to be filed at 90-day intervals beginning July 14, 2025. The order further requires the parties to file motions to govern further proceedings within 30 days of the Federal EPA’s completion of its review of the rule. Management will continue to monitor this 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.

The rule has been challenged by 27 states, numerous companies, trade associations and others. 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. In July 2024, the U.S. Court of Appeals for the District of Columbia Circuit denied those motions to stay and several parties, including AEP and other utilities, filed applications with the United States Supreme Court seeking an emergency stay. The Supreme Court denied those applications in October 2024 and the challenges to the rule before the D.C. Circuit Court of Appeals were placed on an expedited schedule, with oral arguments held in December 2024. On February 5, 2025, the Federal EPA filed an unopposed motion asking the court to withhold issuing an opinion and to hold the case in abeyance for 60 days to allow the new Agency leadership to review the underlying rule. The court granted that motion on February 19, 2025 and ordered the parties to file motions to govern further proceedings by April 21, 2025. On April 21, 2025, the Federal EPA filed an unopposed motion to hold the case in abeyance while the Federal EPA conducts a rulemaking to reassess the challenged rule, with status reports due every 90 days. The court has not ruled on that motion. On June 11, 2025, the Federal EPA proposed to determine that GHG emissions from fossil-fueled power plants do not significantly contribute to air pollution that may endanger public health or the environment. This determination would eliminate all GHG standards for existing and new fossil-fuel plants. As an alternative, the Federal EPA proposed to eliminate GHG standards for existing coal

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and gas units and to keep only certain emission limits applicable to new sources. These proposals have not been finalized. On July 29, 2025, the Federal EPA announced that it would be proposing a repeal of the 2009 Endangerment Finding, which determined that greenhouse gas emissions endanger public health and welfare. The 2009 Endangerment Finding is the basis of Federal EPA’s authority to regulate greenhouse gas emissions under the Clean Air Act and was used to first regulate motor vehicle emissions. We are evaluating the Federal EPA’s proposed repeal of the 2009 Endangerment Finding and its impact on Federal EPA’s authority to regulate greenhouse gas emissions from electric generators. Management cannot predict the outcome of the current litigation or Federal EPA’s proposed actions related to the rule or the Endangerment Finding and any subsequent litigation that may result. Excessive costs to comply with environmental regulations have led to the announcement of early plant closures across the country. The Federal EPA’s 2024 GHG rules, and suite of other new rules issued simultaneously and discussed below, are directed at the fossil-fuel fired electric utility industry and 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.

MATS Rule

In April 2024, the Federal EPA issued a revised MATS rule for power plants. The rule 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 while the current Presidential administration evaluates the rule. In April 2025, the President issued a Proclamation exempting certain generation sources from the requirement to comply with the 2024 MATS rule for two years beyond the rule’s compliance date. In June 2025, the Federal EPA proposed to repeal the 2024 MATS rule and revert to the 2012 MATS rule emission standards. Management does not anticipate any significant challenges complying with the 2024 MATS rule, should the proposed repeal not be finalized.

CCR Rule

The Federal EPA’s CCR Rule regulates the disposal and beneficial re-use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants.  As originally promulgated, the rule applied to active and inactive CCR landfills and surface impoundments at facilities of active electric utility or independent power producers. 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”). 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. See “Federal EPA’s Revised CCR Rule” section in Note 5 for additional information.

Clean Water Act Regulations

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

In April 2024, the Federal EPA finalized further revisions to the ELG rule that establish a zero liquid discharge standard for FGD wastewater, bottom ash transport water, and managed combustion residual leachate, as well as more stringent discharge limits for unmanaged combustion residual leachate. The revised rule provides a new compliance alternative that would eliminate the need to install zero liquid discharge systems for facilities that comply with the 2020 rule’s control technology requirements and commit by December 31, 2025, to retire by 2034. Management is evaluating the compliance alternatives in the rule, taking into consideration the requirements of the other new rules and their combined impacts to operations. Several appeals have been filed with various federal courts challenging the 2024 ELG rule. SWEPCo has also challenged the rule, by filing a joint appeal with a utility trade association in which AEP participates. The various appeals have been consolidated before the United States Court of Appeals for the Eighth Circuit. SWEPCo and the utility trade association filed a motion to stay the rule during the litigation. In October 2024, the court denied the motion. The litigation challenging the ELG Rule is

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being held in abeyance while the new administration evaluates the rule. In March 2025, the Federal EPA announced plans to reconsider the standards established by the 2024 ELG rule. Management cannot predict the outcome of the litigation or any further actions by the Federal EPA related to the ELG rule.

The definition of “waters of the United States” has been subject to rule-making and litigation which has led to inconsistent scope among the states. Management will continue to monitor developments in rule-making and litigation for any potential impact to operations.

Impact of Environmental Regulation on Coal-Fired Generation

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal, remediation and permits. Management continuously 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.

The table below summarizes the net book value, as of June 30, 2025, of generating facilities retired or planned for early retirement in advance of the retirement date currently authorized for ratemaking purposes:

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	$	79.8	$	204.7		2026		(c)	$	16.7
SWEPCo	Pirkey Plant	—		132.6		(d)	2023		(e)	—
SWEPCo	Welsh Plant, Units 1 and 3	300.9		192.7			2028	(f)	(g)	45.9

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

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

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

(d)Represents Arkansas and Texas jurisdictional share.

(e)As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo is seeking recovery of the $37 million Arkansas jurisdictional share and a weighted average cost of capital carrying charge in the base rate case filed in March 2025. The Texas share of the Pirkey Plant will be addressed in SWEPCo’s next base rate case. See the “Regulated Generating Units” section of Note 4 for additional information.

(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 Certificate of Convenience and Necessity (CCN) with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively.

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

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 operating segment provides a comparison of earnings (loss) attributable to AEP Common Shareholders for the three months ended and six months ended June 30, 2025 as compared to the three months ended and six months ended June 30, 2024 in accordance with GAAP. 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, 2025 and 2024, see the discussions of Results of Operations by Subsidiary Registrant.

A detailed discussion of AEP’s 2024 results of operations by operating segment can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operation section included in the 2024 Annual Report.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2025		2024		2025		2024
	(in millions)
Vertically Integrated Utilities	$	432.7	$	65.7	$	756.8	$	626.5
Transmission and Distribution Utilities	223.9		146.8		388.5		297.1
AEP Transmission Holdco	578.4		200.7		813.0		409.4
Generation & Marketing	62.1		(4.8)		164.5		132.8
Corporate and Other	(71.3)		(68.1)		(96.8)		(122.4)
Earnings Attributable to AEP Common Shareholders	$	1,225.8	$	340.3	$	2,026.0	$	1,343.4

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

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VERTICALLY INTEGRATED UTILITIES

Summary of KWh Energy Sales for Vertically Integrated Utilities

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2025	2024	2025	2024
	(in millions of KWhs)
Retail:
Residential	6,372	6,672	15,776	15,232
Commercial	6,297	6,084	12,193	11,853
Industrial	8,595	8,749	16,696	17,001
Miscellaneous	569	568	1,102	1,106
Total Retail	21,833	22,073	45,767	45,192
Wholesale (a)	3,443	3,176	8,234	6,939
Total KWhs	25,276	25,249	54,001	52,131

(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,
	2025	2024	2025	2024
	(in degree days)
Eastern Region
Actual – Heating	118	81	1,735	1,302
Normal – Heating	133	138	1,700	1,743
Actual – Cooling	374	473	382	474
Normal – Cooling	348	339	352	343
Western Region
Actual – Heating	21	5	966	743
Normal – Heating	34	33	903	909
Actual – Cooling	772	921	831	976
Normal – Cooling	738	709	771	739

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Vertically Integrated Utilities
Reconciliation of 2024 to 2025 Earnings Attributable to AEP Common Shareholders
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2024 Earnings Attributable to AEP Common Shareholders	$	65.7	$	626.5
Changes in Revenues:
Retail Revenues	286.6		480.9
Off-system Sales	55.9		62.3
Transmission Revenues	62.9		71.9
Other Revenues	(9.2)		(29.0)
Total Change in Revenues	396.2		586.1
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(49.7)		(126.0)
Other Operation and Maintenance	(28.6)		(26.7)
Asset Impairments and Other Related Charges	13.4		13.4
Depreciation and Amortization	(45.1)		(106.7)
Taxes Other Than Income Taxes	10.0		16.1
Other Income	(0.9)		—
Allowance for Equity Funds Used During Construction	3.2		7.9
Non-Service Cost Components of Net Periodic Pension Cost	(3.6)		(11.8)
Interest Expense	(10.8)		(54.3)
Total Change in Expenses and Other	(112.1)		(288.1)
Income Tax Expense	82.7		(168.3)
Equity Earnings of Unconsolidated Subsidiary	—		(0.1)
Net Income Attributable to Noncontrolling Interests	0.2		0.7
2025 Earnings Attributable to AEP Common Shareholders	$	432.7	$	756.8

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Retail Revenues increased $287 million primarily due to the following:

•A $160 million increase due to a revenue refund provision recorded in 2024 associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.

•A $64 million increase in base rate revenues at I&M and PSO.

•A $40 million increase in weather-normalized revenues primarily in the residential and commercial classes, partially offset by a decrease in the industrial class.

•A $38 million increase in rider revenues across all companies.

•A $27 million increase in fuel revenues primarily due to increases at APCo and I&M, partially offset by a decrease at PSO.

These increases were partially offset by:

•A $42 million decrease in weather-related usage primarily in the residential class driven by an 18% decrease in cooling degree days.

•A $22 million decrease due to regulatory provisions for refund at I&M.

20

•Off-system Sales increased $56 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales at I&M.

•Transmission Revenues increased $63 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Other Revenues decreased $9 million primarily due to revenues from a customer project to enhance transmission resiliency in 2024 at PSO.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation increased $50 million primarily due to an increase at I&M, partially offset by decreases at APCo and PSO.

•Other Operation and Maintenance expenses increased $29 million primarily due to the following:

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

•A $22 million increase in distribution expenses primarily due to vegetation management costs.

•A $17 million increase in PJM and SPP transmission expenses.

•A $6 million increase in nuclear expenses at Cook Plant.

These increases were partially offset by:

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

•Asset Impairments and Other Related Charges decreased $13 million due to the Federal EPA’s revised CCR rules finalized in 2024.

•Depreciation and Amortization expenses increased $45 million primarily due to a higher depreciable base at APCo, I&M and SWEPCo.

•Taxes Other Than Income Taxes decreased $10 million primarily due to lower business and occupation taxes at APCo.

•Interest Expense increased $11 million primarily 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.

•Income Tax Expense decreased $83 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 $30 million decrease due to an increase in PTCs.

These decreases were partially offset by:

•A $60 million increase due to an increase in pretax book income.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

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

•Retail Revenues increased $481 million primarily due to the following:

•A $160 million increase due to a revenue refund provision recorded in 2024 associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.

•A $131 million increase in base rate revenues at I&M and PSO.

•A $110 million increase in rider revenues across all companies.

•A $60 million increase in fuel revenues primarily due to increases at APCo and I&M, partially offset by a decrease at PSO.

•A $41 million increase in weather-related usage primarily in the residential class driven by a 32% increase in heating degree days.

•A $28 million increase in weather-normalized revenues primarily in the residential and commercial classes, partially offset by a decrease in the industrial class.

These increases were partially offset by:

•A $71 million decrease due to regulatory provisions for refund at I&M.

•Off-system Sales increased $62 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales at I&M.

•Transmission Revenues increased $72 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Other Revenues decreased $29 million primarily due to revenues from a customer project to enhance transmission resiliency in 2024 at PSO, a decrease in sales of renewable energy credits at APCo and I&M and a decrease in River Transportation Division (RTD) barging revenues at I&M.

21

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $126 million primarily due to increases at I&M and SWEPCo, partially offset by decreases at APCo and PSO.

•Other Operation and Maintenance expenses increased $27 million primarily due to the following:

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

•A $34 million increase in PJM and SPP transmission expenses.

•A $32 million increase in distribution expenses primarily due to vegetation management costs.

These increases were partially offset by:

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

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

•Asset Impairments and Other Related Charges decreased $13 million due to the Federal EPA’s revised CCR rules finalized in 2024.

•Depreciation and Amortization expenses increased $107 million primarily due to the following:

•A $65 million increase primarily due to a higher depreciable base at APCo, I&M and SWEPCo.

•A $9 million increase due to a prior year deferral of Excess ADIT as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs at I&M.

•An $8 million increase at SWEPCo due to the amortization of the Storm Recovery Funding securitized assets.

•A $5 million increase in regulatory reserves related to Nuclear PTCs at I&M.

•Taxes Other Than Income Taxes decreased $16 million primarily due to lower business and occupation taxes at APCo.

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

•Non-Service Cost Components of Net Periodic Benefit Cost increased $12 million primarily due to an increase in loss amortization and discount rates from 2024 to 2025.

•Interest Expense increased $54 million primarily 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.

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

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

•A $57 million increase due to an increase in pretax book income.

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

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.

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

22

TRANSMISSION AND DISTRIBUTION UTILITIES

Summary of KWh Energy Sales for Transmission and Distribution Utilities

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2025	2024	2025	2024
	(in millions of KWhs)
Retail:
Residential	6,299	6,593	13,310	12,873
Commercial	11,042	9,209	20,630	17,200
Industrial	7,048	6,826	13,804	13,638
Miscellaneous	172	180	344	360
Total Retail (a)	24,561	22,808	48,088	44,071
Wholesale (b)	464	253	1,131	843
Total KWhs	25,025	23,061	49,219	44,914

(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,
	2025	2024	2025	2024
	(in degree days)
Eastern Region
Actual – Heating	170	110	2,077	1,573
Normal – Heating	173	181	1,993	2,052
Actual – Cooling	336	422	342	422
Normal – Cooling	323	306	325	309
Western Region
Actual – Heating	4	1	296	162
Normal – Heating	4	3	208	198
Actual – Cooling	992	1,198	1,153	1,344
Normal – Cooling	909	949	1,021	1,086

23

Transmission and Distribution Utilities
Reconciliation of 2024 to 2025 Earnings Attributable to AEP Common Shareholders
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2024 Earnings Attributable to AEP Common Shareholders	$	146.8	$	297.1
Changes in Revenues:
Retail Revenues	38.2		64.4
Off-system Sales	12.9		25.8
Transmission Revenues	(6.2)		14.2
Other Revenues	(30.6)		(53.8)
Total Change in Revenues	14.3		50.6
Changes in Expenses and Other:
Purchased Electricity for Resale	(3.9)		7.9
Purchased Electricity from AEP Affiliates	10.7		41.4
Other Operation and Maintenance	(20.4)		(78.3)
Asset Impairments and Other Related Charges	52.9		52.9
Depreciation and Amortization	25.4		45.0
Taxes Other Than Income Taxes	18.7		4.3
Other Income	(2.6)		(2.0)
Allowance for Equity Funds Used During Construction	(0.2)		4.2
Non-Service Cost Components of Net Periodic Benefit Cost	1.1		0.6
Interest Expense	(4.2)		(19.6)
Total Change in Expenses and Other	77.5		56.4
Income Tax Expense	(15.5)		(17.8)
Equity Earnings (Loss) of Unconsolidated Subsidiary	0.8		2.2
2025 Earnings Attributable to AEP Common Shareholders	$	223.9	$	388.5

Second Quarter of 2025 Compared to Second Quarter of 2024

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

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

•A $43 million increase in base case and rider revenues.

•A $24 million increase in weather-normalized revenues primarily in the commercial and industrial classes in Ohio.

These increases were partially offset by:

•An $11 million decrease due to lower prices and lower customer participation in OPCo’s SSO.

•A $9 million decrease in weather-related usage driven by a 20% decrease in cooling degree days in the Eastern Region and a 17% decrease in cooling degree days in the Western Region.

•A $7 million decrease in weather-normalized revenues primarily in the residential class in Texas.

•Off-system Sales increased $13 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.

•Transmission Revenues decreased $6 million primarily due to the following:

•A $35 million decrease due to lower peak loads included in the 2025 billing rates in Texas.

This decrease was partially offset by:

•A $25 million increase in interim rates driven by increased transmission investments in Texas.

24

•Other Revenues decreased $31 million primarily due to the maturity of Transition Funding III LLC securitization bonds in December 2024 and third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

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

•Purchased Electricity from AEP Affiliates expenses decreased $11 million primarily due to decreased recoverable purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $20 million primarily due to the following:

•A $29 million increase in recoverable transmission expenses in Texas.

•A $16 million increase for transmission and distribution related expenses in Texas.

•An $8 million increase in transmission expenses in Ohio primarily due to an increase in recoverable PJM expenses.

•An $8 million increase in distribution expenses in Ohio primarily related to recoverable storm restoration costs and recoverable vegetation management expenses.

These increases were partially offset by:

•A $33 million decrease in employee-related expenses due to the voluntary severance program that occurred in the second quarter of 2024.

•A $9 million decrease related to recoverable energy assistance program expenses for qualified Ohio customers.

•Asset Impairments and Other Related Charges decreased $53 million primarily due to the Federal EPA revised CCR rules finalized in 2024.

•Depreciation and Amortization expenses decreased $25 million primarily due to the following:

•A $16 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

•An $11 million decrease due to the deferral of eligible costs related to HB 5247.

•A $7 million decrease due to capital rider under-recoveries in Ohio.

These decreases were partially offset by:

•A $9 million increase due to a higher depreciable base in Texas.

•Taxes Other Than Income Taxes decreased $19 million primarily due to the following:

•A $12 million decrease due to lower property taxes in Ohio.

•A $6 million decrease in state excise taxes in Ohio due to decreased billed KWhs in 2025.

•Interest Expense increased $4 million primarily due to the following:

•An $8 million increase due to higher debt balances and interest rates in Texas.

•A $5 million increase due to a decrease of capitalization of AFUDC on prepaid pension and OPEB in Texas.

These increases were partially offset by:

•A $12 million decrease due to the deferral of eligible costs related to HB 5247.

•Income Tax Expense increased $16 million primarily due to the following:

•A $19 million increase due to an increase in pretax book income.

This increase was partially offset by:

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

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

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

•Retail Revenues increased $64 million primarily due to the following:

•A $133 million increase in base case and rider revenues.

•A $34 million increase in weather-related usage driven by a 32% increase in heating degree days in the Eastern Region and an 83% increase in heating degree days in the Western Region.

These increases were partially offset by:

•An $88 million decrease due to lower prices and lower customer participation in OPCo’s SSO.

•An $10 million decrease in weather-normalized revenues primarily in the residential class in Texas and Ohio partially offset by an increase in the commercial class in Ohio.

•Off-system Sales increased $26 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.

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

•A $42 million increase in interim rates driven by increased transmission investments in Texas.

•A $6 million increase in Ohio primarily due to continued transmission investment.

These increases were partially offset by:

•A $34 million decrease due to lower peak loads included in the 2025 billing rates in Texas.

25

•Other Revenues decreased $54 million primarily due to the following:

•A $42 million decrease in Texas primarily due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

•A $7 million decrease in recoverable sales of renewable energy credits in Ohio.

•A $5 million decrease due to third-party Legacy Generation Resource Rider revenue 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 $8 million primarily due to the following:

•A $41 million decrease in recoverable auction purchases primarily due to lower prices in Ohio.

•A $12 million decrease in recoverable alternative energy rider expenses in Ohio.

These decreases were partially offset by:

•A $30 million estimated reduction in regulatory assets for OVEC-related purchased power costs that are no longer probable of future recovery due to recently approved legislation in Ohio.

•A $17 million increase in recoverable OVEC costs.

•Purchased Electricity from AEP Affiliates expenses decreased $41 million primarily due to decreased recoverable purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $78 million primarily due to the following:

•A $58 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $42 million increase in recoverable transmission expenses in Texas.

•An $18 million increase in transmission and distribution related expenses in Texas.

•A $7 million increase in property and liability insurance expenses in Texas.

These increases were partially offset by:

•A $32 million decrease in employee-related expenses due to the voluntary severance program that occurred in the second quarter of 2024.

•A $19 million decrease related to recoverable energy assistance program expenses for qualified Ohio customers.

•Asset Impairments and Other Related Charges decreased $53 million due to the Federal EPA's Revised CCR rules finalized in 2024.

•Depreciation and Amortization expenses decrease $45 million due to the following:

•A $32 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

•A $19 million decrease primarily due to capital rider under-recoveries in Ohio.

•An $11 million decrease due to the deferral of eligible costs related to HB 5247.

These decreases were partially offset by:

•A $19 million increase due to a higher depreciable base in Texas.

•Interest Expense increased $20 million primarily due to:

•A $26 million increase due to higher debt balances in Ohio and higher debt balances and interest rates in Texas.

•A $5 million increase due to a decrease of capitalization of AFUDC on prepaid pension and OPEB in Texas.

These increases were partially offset by:

•A $12 million decrease due to the deferral of eligible costs related to HB 5247.

•Income Tax Expense increased $18 million due to:

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

This increase was partially offset by:

•A $7 million decrease due to an increase in amortization of Excess ADIT.

26

AEP TRANSMISSION HOLDCO

Summary of Investment in Transmission Assets for AEP Transmission Holdco

	June 30,
	2025		2024
	(in millions)
Plant in Service	$	16,495.8	$	15,013.1
Construction Work in Progress	2,371.2		2,115.8
Accumulated Depreciation and Amortization	1,810.0		1,481.4
Total Transmission Property, Net	$	17,057.0	$	15,647.5

AEP Transmission Holdco
Reconciliation of 2024 to 2025 Earnings Attributable to AEP Common Shareholders
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2024 Earnings Attributable to AEP Common Shareholders	$	200.7	$	409.4
Changes in Transmission Revenues:
Transmission Revenues	266.7		311.5
Total Change in Transmission Revenues	266.7		311.5
Changes in Expenses and Other:
Other Operation and Maintenance	0.7		0.4
Depreciation and Amortization	(12.2)		(20.3)
Taxes Other Than Income Taxes	—		(0.6)
Interest and Investment Income	(2.6)		(4.4)
Allowance for Equity Funds Used During Construction	(1.1)		3.5
Non-Service Cost Components of Net Periodic Pension Cost	0.2		(0.5)
Interest Expense	(5.4)		(5.4)
Total Change in Expenses and Other	(20.4)		(27.3)
Income Tax Expense	196.3		183.7
Equity Earnings of Unconsolidated Subsidiary	(4.4)		(3.9)
Net Income Attributable to Noncontrolling Interests	(60.5)		(60.4)
2025 Earnings Attributable to AEP Common Shareholders	$	578.4	$	813.0

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Transmission Revenues increased $267 million primarily due to the following:

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

•A $50 million increase due to continued transmission investment.

27

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

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

•Interest Expense increased $5 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense decreased $196 million primarily due to the following:

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

This decrease was partially offset by:

•A $51 million increase due to an increase in pretax book income.

•A $7 million increase due to an increase in state taxes.

•Net Income Attributable to Noncontrolling Interests increased $61 million primarily due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

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

•Transmission Revenues increased $312 million primarily due to the following:

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

•A $97 million increase due to continued transmission investment.

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

•Depreciation and Amortization expenses increased $20 million due to a higher depreciable base.

•Interest Expense increased $5 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense decreased $184 million primarily due to the following:

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

This decrease was partially offset by:

•A $59 million increase due to an increase in pretax book income.

•An $8 million increase due to an increase in state taxes.

•Net Income Attributable to Noncontrolling Interests increased $60 million primarily due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.

28

GENERATION & MARKETING

Reconciliation of 2024 to 2025 Earnings Attributable to AEP Common Shareholders
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2024 Earnings (Loss) Attributable to AEP Common Shareholders	$	(4.8)	$	132.8
Changes in Revenues:
Merchant Generation	15.9		39.3
Renewable Generation	(8.8)		(15.6)
Retail, Trading and Marketing	91.6		258.4
Total Change in Revenues	98.7		282.1
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(128.6)		(338.5)
Other Operation and Maintenance	42.7		43.8
Asset Impairments and Other Related Charges	76.2		76.2
Depreciation and Amortization	0.8		4.9
Taxes Other Than Income Taxes	0.2		(0.3)
Interest and Investment Income	(1.0)		(6.0)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.5)		(0.9)
Interest Expense	2.9		7.0
Total Change in Expenses and Other	(7.3)		(213.8)
Income Tax Expense	(24.5)		(35.7)
Equity Earnings of Unconsolidated Subsidiaries	—		(0.9)
2025 Earnings Attributable to AEP Common Shareholders	$	62.1	$	164.5

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Merchant Generation increased $16 million primarily due to higher realized prices in 2025.

•Renewable Generation decreased $9 million primarily due to the sale of Onsite Partners in September 2024.

•Retail, Trading and Marketing increased $92 million primarily due to higher MTM hedging activity and higher market prices in 2025.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $129 million primarily due to an increase in energy costs in 2025.

•Other Operation and Maintenance expenses decreased $43 million primarily due to renewable contract termination proceeds in 2025 and the sale of Onsite Partners in September 2024.

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

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

•A $19 million increase due to an increase in pretax book income.

•A $2 million increase due to a decrease in the amortization of deferred ITCs.

29

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

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

•Merchant Generation increased $39 million primarily due to higher realized prices in 2025.

•Renewable Generation decreased $16 million primarily due to the sale of Onsite Partners in September 2024.

•Retail, Trading and Marketing increased $258 million primarily due to higher MTM hedging activity and higher market prices in 2025.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $339 million primarily due to an increase in energy costs in 2025.

•Other Operation and Maintenance expenses decreased $44 million primarily due to renewable contract termination proceeds in 2025 and the sale of Onsite Partners in September 2024.

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

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

•Interest and Investment Income decreased $6 million primarily due to the sale of Onsite Partners in September 2024.

•Interest Expense decreased $7 million due to lower advances from affiliates.

•Income Tax Expense increased $36 million primarily due to:

•A $16 million increase due to a decrease in amortization of deferred ITCs primarily from the sale of NMRD in 2024.

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

30

CORPORATE AND OTHER

Second Quarter of 2025 Compared to Second Quarter of 2024

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $68 million in 2024 to a loss of $71 million in 2025 primarily due to:

•A $10 million decrease due to the cessation of AEP T&D Services substation construction contracts.

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

•A $5 million decrease in interest income primarily due to lower advances to affiliates.

These decreases in earnings were partially offset by:

•A $19 million increase in Income Tax Benefit primarily due to the following:

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

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

•A $4 million increase due to an increase in deferred ITC amortization and PTCs.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $122 million in 2024 to a loss of $97 million in 2025 primarily due to:

•A $28 million increase in Income Tax Benefit primarily due to the following:

•A $17 million increase due to an increase in deferred ITC amortization and PTCs.

•An $11 million increase due to a decrease in state taxes.

•A $13 million decrease in interest expense due to lower interest rates.

•A $12 million increase in equity earnings.

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

These increases in earnings were partially offset by:

•A $23 million decrease at EIS primarily due to increased insurance reserves.

•A $16 million decrease in interest income primarily due to lower advances to affiliates.

AEP CONSOLIDATED INCOME TAXES

Second Quarter of 2025 Compared to Second Quarter of 2024

Income Tax Benefit increased $258 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 $32 million increase due to an increase in deferred ITC amortization and PTCs.

These increases in Income Tax Benefit were partially offset by:

•A $145 million decrease due to an increase in pretax book income.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

Income Tax Benefit decreased $10 million primarily due to:

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

•A $158 million decrease due to an increase in pretax book income.

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

•A $15 million decrease due to a decrease in amortization of Excess ADIT.

These decreases in Income Tax Benefit were partially offset by:

•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 $33 million increase due to an increase in deferred ITC amortization and PTCs.

31

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, 2025				December 31, 2024
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	44,525.5	57.8	%	$	42,642.8	59.1	%
Short-term Debt	1,501.6		2.0		2,523.8		3.5
Total Debt	46,027.1		59.8		45,166.6		62.6
AEP Common Equity	29,871.1		38.8		26,943.8		37.3
Noncontrolling Interests	1,097.3		1.4		42.3		0.1
Total Debt and Equity Capitalization	$	76,995.5	100.0	%	$	72,152.7	100.0	%

AEP’s ratio of debt-to-total capital decreased from 62.6% to 59.8% as of December 31, 2024 and June 30, 2025, respectively, primarily due to an increase in earnings and the Midwest Transmission Holdings Noncontrolling Interest transaction, partially offset by an increase in long-term debt to support our 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 foreseeable future.  As of June 30, 2025, AEP had $6 billion of revolving credit facilities to support its commercial paper program.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, long-term asset securitizations, leasing agreements, hybrid securities or common stock, including the settlement of the March 2025 forward sale of equity, which is expected to occur on or prior to December 31, 2026. 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.

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. AEP continues monitoring the current bank environment and any impacts thereof. AEP was not materially impacted by these conditions during the six months ended June 30, 2025.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of June 30, 2025, available liquidity was approximately $5.6 billion as illustrated in the table below:

		Amount		Maturity
Commercial Paper Backup:		(in millions)
	Revolving Credit Facility	$	5,000.0	March 2029
	Revolving Credit Facility	1,000.0		March 2027
Cash and Cash Equivalents		227.3
Total Liquidity Sources		6,227.3
Less:	AEP Commercial Paper Outstanding	600.0
Net Available Liquidity		$	5,627.3

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 2025 was $2.9 billion.  The weighted-average interest rate for AEP’s commercial paper for the six months ended June 30, 2025 was 4.64%.

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Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of June 30, 2025 was $361 million with maturities ranging from July 2025 to July 2026.

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 2026. As of June 30, 2025, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements.  Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of June 30, 2025, this contractually-defined percentage was 56.6%. 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.

March 2025 Forward Sale of Equity

See “Forward Sale of Equity” section of Note 13 for additional information regarding AEP’s forward sale of 22,549,020 shares of common stock in March 2025.

ATM Program

In 2024, approximately $0.4 billion of common stock was offered and sold under the ATM program. There were no issuances under the ATM program for the six months ended June 30, 2025. Approximately $1.3 billion of equity is available for issuance under the ATM program upon the filing of a prospectus supplement.

Dividend Policy and Restrictions

The Board of Directors of AEP (AEP Board) declared a quarterly dividend of $0.93 per share in July 2025. Future dividends are at the discretion of the AEP Board and 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 13 for additional information.

Credit Ratings

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

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CASH FLOW

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

	Six Months Ended  June 30,
	2025		2024
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	246.0	$	379.0
Net Cash Flows from Operating Activities	2,671.1		2,904.2
Net Cash Flows Used for Investing Activities	(5,347.3)		(3,249.7)
Net Cash Flows from Financing Activities	2,708.8		214.4
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	32.6		(131.1)
Cash, Cash Equivalents and Restricted Cash at End of Period	$	278.6	$	247.9

Operating Activities

	Six Months Ended  June 30,
	2025		2024
	(in millions)
Net Income	$	2,090.5	$	1,348.2
Non-Cash Adjustments to Net Income (a)	1,518.5		1,596.6
Mark-to-Market of Risk Management Contracts	(240.6)		(75.0)
Pension Contributions to Qualified Plan Trust	(94.7)		—
Property Taxes	240.6		213.2
Deferred Fuel Over/Under-Recovery, Net	(41.3)		120.0
Change in Other Noncurrent Assets	(439.5)		(131.0)
Change in Other Noncurrent Liabilities	41.4		189.9
Change in Certain Components of Working Capital	(403.8)		(357.7)
Net Cash Flows from Operating Activities	$	2,671.1	$	2,904.2

(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 decreased by $233 million primarily due to the following:

•A $457 million decrease in cash from Change in Other Noncurrent Assets and Change in Other Noncurrent Liabilities. This decrease is primarily due to changes in regulatory assets and liabilities driven by timing differences in collections from and refunds to customers under rate rider mechanisms.

•A $166 million decrease in cash due to changes in risk management contract collateral positions.

•A $161 million decrease in cash primarily due to the timing of fuel and purchase power related revenues and expenses.

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

These decreases in cash were partially offset by:

•A $664 million increase in cash from Net Income, after non-cash adjustments. See “Results of Operations” for further detail.

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Investing Activities

	Six Months Ended  June 30,
	2025		2024
	(in millions)
Construction Expenditures	$	(4,020.2)	$	(3,318.3)
Acquisitions of Generation Facilities	(1,359.3)		—
Acquisitions of Nuclear Fuel	(45.6)		(69.8)
Proceeds from Sale of Equity Method Investment	—		114.0
Other	77.8		24.4
Net Cash Flows Used for Investing Activities	$	(5,347.3)	$	(3,249.7)

Net Cash Flows Used for Investing Activities increased by $2.1 billion primarily due to the following:

•A $1.4 billion increase due to the acquisitions of Green Country Power Plant, Pixley Solar Energy Facility and Flat Ridge IV Wind Energy Facility. See “Acquisitions” section of Note 6 for additional information.

•A $702 million increase in Construction Expenditures primarily due to increases in Vertically Integrated Utilities of $313 million, Transmission and Distribution Utilities of $247 million and AEP Transmission Holdco of $119 million.

•A $114 million decrease in Proceeds from Sale of Equity Method Investment. See “Disposition of NMRD” section of Note 6 for additional information.

Financing Activities

	Six Months Ended  June 30,
	2025		2024
	(in millions)
Issuance of Common Stock	$	131.8	$	475.8
Issuance/Retirement of Debt, Net	816.9		745.7
Principal Payments for Finance Lease Obligations	(25.0)		(35.8)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	2,782.9		—
Dividends Paid on Common Stock	(1,000.5)		(936.0)
Other	2.7		(35.3)
Net Cash Flows from Financing Activities	$	2,708.8	$	214.4

Net Cash Flows from Financing Activities increased by $2.5 billion primarily due to the following:

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

•A $445 million decrease in retirements of long-term debt. See Note 13 - Financing Activities for additional information.

These increases in cash were partially offset by:

•A $500 million decrease in issuances of long-term debt. See Note 13 - Financing Activities for additional information.

•A $344 million decrease in issuances of common stock primarily under AEP’s ATM Program. See Note 13 - Financing Activities for additional information.

See the “Long-term Debt Subsequent Events” section of Note 13 for Long-term debt and other securities issued, retired and principal payments made after June 30, 2025 through July 30, 2025, the date that the second quarter Form 10-Q was filed.

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BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $11.5 billion of capital expenditures in 2025.  For the four-year period, 2026 through 2029, management forecasts capital expenditures of $42.9 billion. Management’s forecasted capital expenditures reflect planned increases in investments for transmission infrastructure and new generation resources to support 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, inflation and the ability to access capital.  Management has funded, or expects to fund, these capital expenditures through cash flows from operations, proceeds from the strategic sale of assets 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. For more information of forecasted capital expenditures, see the “Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2024 Annual Report.

SIGNIFICANT CASH REQUIREMENTS

A summary of significant cash requirements is included in the 2024 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 2024 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, asset retirement obligations and the impact of new accounting standards and SEC rulemaking activity.

ACCOUNTING STANDARDS

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

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

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

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

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

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

The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2024:

MTM Derivative Contract Net Assets (Liabilities)

Six Months Ended June 30, 2025
	Vertically Integrated Utilities		Transmission and Distribution Utilities		Generation & Marketing		Total
	(in millions)
Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of December 31, 2024	$	91.8	$	(48.0)	$	161.8	$	205.6
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period	(72.0)		(1.1)		(17.0)		(90.1)
Fair Value of New Contracts at Inception When Entered During the Period (a)	—		—		10.7		10.7
Changes in Fair Value Due to Market Fluctuations During the Period (b)	(20.5)		—		50.0		29.5
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	285.1		1.1		—		286.2
Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of June 30, 2025	$	284.4	$	(48.0)	$	205.5	441.9
Commodity Cash Flow Hedge Contracts							115.9
Fair Value Hedge Contracts							(47.9)
Collateral Deposits							(79.4)
Total MTM Derivative Contract Net Assets as of June 30, 2025							$	430.5

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

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

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

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

Credit Risk

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

AEP has risk management contracts (includes non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of June 30, 2025, credit exposure net of collateral to sub investment grade counterparties was approximately 6.2%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).

As of June 30, 2025, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

Counterparty Credit Quality	Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties >10% of Net Exposure	Net Exposure of Counterparties >10%
	(in millions, except number of counterparties)
Investment Grade	$	642.8	$	94.9	$	547.9	3	$	351.1
Non-investment Grade	3.5		—		3.5		2	3.5
No External Ratings:
Internal Investment Grade	18.4		—		18.4		3	13.4
Internal Non-investment Grade	104.4		70.5		33.9		2	27.8
Total as of June 30, 2025	$	769.1	$	165.4	$	603.7

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

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

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of June 30, 2025, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

Management calculates the VaR for both a trading and non-trading portfolio. The trading portfolio consists primarily of contracts related to energy trading and marketing activities. The non-trading portfolio consists primarily of economic hedges of generation and retail supply activities.

38

The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:

VaR Model

Trading Portfolio

Six Months Ended								Twelve Months Ended
June 30, 2025								December 31, 2024
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	0.1	$	0.7	$	0.2	$	0.1	$	0.2	$	1.7	$	0.3	$	0.1

VaR Model

Non-Trading Portfolio

Six Months Ended								Twelve Months Ended
June 30, 2025								December 31, 2024
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	6.2	$	28.8	$	12.6	$	4.6	$	37.9	$	98.6	$	19.3	$	7.6

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

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

Interest Rate Risk

AEP is exposed to interest rate market fluctuations in the normal course of business operations. Prior to 2022, interest rates remained at low levels and the Federal Reserve maintained the federal funds target range at 0.0% to 0.25% for much of 2021. During 2022 and 2023, the Federal Reserve approved 11 rate increases for a total cumulative increase of 5.25%. In light of the progress on inflation and the balance of risks, during 2024, the Federal Reserve authorized three rate decreases for a total cumulative decrease of 1.0%. AEP has outstanding short and long-term debt which is subject to variable rates. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes on interest rates. For the six months ended June 30, 2025 and 2024, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $34 million and $25 million, respectively.

39

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2025 and 2024

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

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2025		2024		2025		2024
REVENUES
Vertically Integrated Utilities	$	2,934.5	$	2,572.0	$	6,020.0	$	5,473.2
Transmission and Distribution Utilities	1,442.6		1,428.8		2,958.1		2,912.0
Generation & Marketing	551.0		442.5		1,281.6		958.4
Other Revenues	158.8		135.9		290.6		261.3
TOTAL REVENUES	5,086.9		4,579.2		10,550.3		9,604.9
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	1,541.4		1,368.5		3,394.3		2,944.3
Other Operation	537.6		817.3		1,290.0		1,579.6
Maintenance	390.7		351.5		709.2		669.0
Asset Impairments and Other Related Charges	—		142.5		—		142.5
Depreciation and Amortization	853.1		821.9		1,686.5		1,609.0
Taxes Other Than Income Taxes	365.0		393.6		787.0		804.0
TOTAL EXPENSES	3,687.8		3,895.3		7,867.0		7,748.4
OPERATING INCOME	1,399.1		683.9		2,683.3		1,856.5
Other Income (Expense):
Other Income	15.5		13.1		23.3		26.7
Allowance for Equity Funds Used During Construction	57.1		55.2		114.4		98.8
Non-Service Cost Components of Net Periodic Benefit Cost	34.6		37.4		69.7		82.5
Interest Expense	(489.5)		(465.6)		(984.4)		(901.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	1,016.8		324.0		1,906.3		1,163.3
Income Tax Expense (Benefit)	(250.9)		6.7		(125.4)		(135.2)
Equity Earnings of Unconsolidated Subsidiaries	20.6		25.2		58.8		49.7
NET INCOME	1,288.3		342.5		2,090.5		1,348.2
Net Income Attributable to Noncontrolling Interests	62.5		2.2		64.5		4.8
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1,225.8	$	340.3	$	2,026.0	$	1,343.4
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	534,283,554		528,898,816		533,839,985		527,725,426
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	2.29	$	0.64	$	3.80	$	2.55
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	536,425,635		530,140,990		535,547,029		528,868,693
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	2.29	$	0.64	$	3.78	$	2.54
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Net Income	$	1,288.3	$	342.5	$	2,090.5	$	1,348.2
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $(8.8) and $5.9 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $(2.7) and $4.3 for the Six Months Ended June 30, 2025 and 2024, Respectively	(33.2)		22.4		(10.1)		16.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $0.1 and $(0.2) for the Six Months Ended June 30, 2025 and 2024, Respectively	0.3		(0.1)		0.6		(0.7)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(32.9)		22.3		(9.5)		15.5
TOTAL COMPREHENSIVE INCOME	1,255.4		364.8		2,081.0		1,363.7
Total Comprehensive Income Attributable To Noncontrolling Interests	62.5		2.2		64.5		4.8
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1,192.9	$	362.6	$	2,016.5	$	1,358.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

41

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Six Months Ended June 30, 2025 and 2024

(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, 2023	527.4	$	3,427.9	$	9,073.9	$	12,800.4		$	(55.5)	$	39.2	$	25,285.9
Issuance of Common Stock	0.8	5.4		35.2									40.6
Common Stock Dividends						(465.5)		(a)			(1.4)		(466.9)
Other Changes in Equity				(14.8)									(14.8)
Net Income						1,003.1					2.6		1,005.7
Other Comprehensive Loss									(6.8)				(6.8)
TOTAL EQUITY – MARCH 31, 2024	528.2	3,433.3		9,094.3		13,338.0			(62.3)		40.4		25,843.7
Issuance of Common Stock	4.9	32.1		403.1									435.2
Common Stock Dividends						(467.0)		(a)			(2.1)		(469.1)
Other Changes in Equity				1.1									1.1
Net Income						340.3					2.2		342.5
Other Comprehensive Income									22.3				22.3
TOTAL EQUITY – JUNE 30, 2024	533.1	$	3,465.4	$	9,498.5	$	13,211.3		$	(40.0)	$	40.5	$	26,175.7
TOTAL EQUITY – DECEMBER 31, 2024	534.1	$	3,471.6	$	9,606.1	$	13,869.2		$	(3.1)	$	42.3	$	26,986.1
Issuance of Common Stock	1.1	7.1		68.3									75.4
Common Stock Dividends						(500.0)		(b)			(1.0)		(501.0)
Other Changes in Equity				(22.1)									(22.1)
Net Income						800.2					2.0		802.2
Other Comprehensive Income									23.4				23.4
TOTAL EQUITY – MARCH 31, 2025	535.2	3,478.7		9,652.3		14,169.4			20.3		43.3		27,364.0
Issuance of Common Stock	0.6	3.7		52.7									56.4
Common Stock Dividends						(498.5)		(b)			(1.0)		(499.5)
Other Changes in Equity				9.1							0.1		9.2
Midwest Transmission Holdings Noncontrolling Interest Transaction				1,790.5							992.4		2,782.9
Net Income						1,225.8					62.5		1,288.3
Other Comprehensive Loss									(32.9)				(32.9)
TOTAL EQUITY – JUNE 30, 2025	535.8	$	3,482.4	$	11,504.6	$	14,896.7		$	(12.6)	$	1,097.3	$	30,968.4

(a)    Cash dividends declared per AEP common share were $0.88.

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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

42

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2025 and December 31, 2024

(in millions)

(Unaudited)

	June 30,		December 31,
	2025		2024
CURRENT ASSETS
Cash and Cash Equivalents	$	227.3	$	202.9
Restricted Cash (June 30, 2025 and December 31, 2024 Amounts Include $51.3 and $43.1, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding, Storm Recovery Funding and Cost Recovery Funding)	51.3		43.1
Other Temporary Investments (June 30, 2025 and December 31, 2024 Amounts Include $197.9 and $206.7, Respectively, Related to EIS)	212.0		215.4
Accounts Receivable:
Customers	1,134.6		1,100.1
Accrued Unbilled Revenues	393.7		367.0
Pledged Accounts Receivable – AEP Credit	1,279.0		1,161.5
Miscellaneous	53.4		64.1
Allowance for Credit Losses	(63.6)		(60.8)
Total Accounts Receivable	2,797.1		2,631.9
Fuel	616.9		748.9
Materials and Supplies	1,005.1		966.2
Risk Management Assets	469.3		210.4
Accrued Tax Benefits	111.6		38.2
Regulatory Asset for Under-Recovered Fuel Costs	547.4		445.9
Prepayments and Other Current Assets	283.9		285.9
TOTAL CURRENT ASSETS	6,321.9		5,788.8
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	26,039.7		24,829.7
Transmission	40,304.3		38,871.9
Distribution	32,125.2		31,061.9
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	8,378.2		7,491.6
Construction Work in Progress	6,945.3		6,346.9
Total Property, Plant and Equipment	113,792.7		108,602.0
Accumulated Depreciation and Amortization	27,455.6		26,186.4
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	86,337.1		82,415.6
OTHER NONCURRENT ASSETS
Regulatory Assets	4,870.2		5,129.2
Securitized Assets	973.1		554.3
Spent Nuclear Fuel and Decommissioning Trusts	4,609.7		4,395.1
Goodwill	52.5		52.5
Long-term Risk Management Assets	258.9		289.1
Operating Lease Assets	580.6		580.1
Deferred Charges and Other Noncurrent Assets	3,774.5		3,873.3
TOTAL OTHER NONCURRENT ASSETS	15,119.5		14,873.6
TOTAL ASSETS	$	107,778.5	$	103,078.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

43

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

June 30, 2025 and December 31, 2024

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

(Unaudited)

			June 30,		December 31,
			2025		2024
CURRENT LIABILITIES
Accounts Payable			$	2,714.2	$	2,637.6
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			900.0		900.0
Other Short-term Debt			601.6		1,623.8
Total Short-term Debt			1,501.6		2,523.8
Long-term Debt Due Within One Year (June 30, 2025 and December 31, 2024 Amounts Include $181.9 and $216.5, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)			3,212.4		3,335.0
Risk Management Liabilities			106.1		100.0
Customer Deposits			454.3		454.7
Accrued Taxes			1,527.8		1,922.1
Accrued Interest			479.2		453.3
Obligations Under Operating Leases			91.0		91.9
Other Current Liabilities			1,356.7		1,490.9
TOTAL CURRENT LIABILITIES			11,443.3		13,009.3
NONCURRENT LIABILITIES
Long-term Debt (June 30, 2025 and December 31, 2024 Amounts Include $1,354.4 and $826.5, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)			41,313.1		39,307.8
Long-term Risk Management Liabilities			191.6		224.4
Deferred Income Taxes			10,521.7		9,972.4
Regulatory Liabilities and Deferred Investment Tax Credits			7,973.9		8,344.0
Asset Retirement Obligations			3,625.1		3,530.6
Employee Benefits and Pension Obligations			270.5		360.7
Obligations Under Operating Leases			506.5		504.3
Deferred Credits and Other Noncurrent Liabilities			913.8		800.6
TOTAL NONCURRENT LIABILITIES			65,316.2		63,044.8
TOTAL LIABILITIES			76,759.5		76,054.1
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
MEZZANINE EQUITY
Contingently Redeemable Performance Share Awards			50.6		37.8
TOTAL MEZZANINE EQUITY			50.6		37.8
EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2025	2024
Shares Authorized	600,000,000	600,000,000
Shares Issued	535,755,643	534,094,530
(1,186,815 Shares were Held in Treasury as of June 30, 2025 and December 31, 2024, Respectively)			3,482.4		3,471.6
Paid-in Capital			11,504.6		9,606.1
Retained Earnings			14,896.7		13,869.2
Accumulated Other Comprehensive Income (Loss)			(12.6)		(3.1)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			29,871.1		26,943.8
Noncontrolling Interests			1,097.3		42.3
TOTAL EQUITY			30,968.4		26,986.1
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY			$	107,778.5	$	103,078.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

44

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2025		2024
OPERATING ACTIVITIES
Net Income	$	2,090.5	$	1,348.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,686.5		1,609.0
Deferred Income Taxes	(53.6)		(56.1)
Asset Impairments and Other Related Charges	—		142.5
Allowance for Equity Funds Used During Construction	(114.4)		(98.8)
Mark-to-Market of Risk Management Contracts	(240.6)		(75.0)
Pension Contributions to Qualified Plan Trust	(94.7)		—
Property Taxes	240.6		213.2
Deferred Fuel Over/Under-Recovery, Net	(41.3)		120.0
Change in Other Noncurrent Assets	(439.5)		(131.0)
Change in Other Noncurrent Liabilities	41.4		189.9
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(176.4)		(209.3)
Fuel, Materials and Supplies	114.3		111.3
Accounts Payable	286.9		77.0
Accrued Taxes, Net	(468.5)		(301.3)
Other Current Assets	10.6		(144.0)
Other Current Liabilities	(170.7)		108.6
Net Cash Flows from Operating Activities	2,671.1		2,904.2
INVESTING ACTIVITIES
Construction Expenditures	(4,020.2)		(3,318.3)
Purchases of Investment Securities	(1,336.5)		(1,190.1)
Sales of Investment Securities	1,311.0		1,157.1
Acquisitions of Generation Facilities	(1,359.3)		—
Acquisitions of Nuclear Fuel	(45.6)		(69.8)
Proceeds from Sale of Equity Method Investment	—		114.0
Other Investing Activities	103.3		57.4
Net Cash Flows Used for Investing Activities	(5,347.3)		(3,249.7)
FINANCING ACTIVITIES
Issuance of Common Stock	131.8		475.8
Issuance of Long-term Debt	3,163.2		3,663.3
Issuance of Short-term Debt with Original Maturities greater than 90 Days	319.9		376.6
Change in Short-term Debt with Original Maturities less than 90 Days, Net	(764.3)		(860.0)
Retirement of Long-term Debt	(1,324.1)		(1,769.1)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days	(577.8)		(665.1)
Principal Payments for Finance Lease Obligations	(25.0)		(35.8)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	2,782.9		—
Dividends Paid on Common Stock	(1,000.5)		(936.0)
Other Financing Activities	2.7		(35.3)
Net Cash Flows from Financing Activities	2,708.8		214.4
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	32.6		(131.1)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	246.0		379.0
Cash, Cash Equivalents and Restricted Cash at End of Period	$	278.6	$	247.9
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	946.2	$	881.0
Net Cash Paid for Income Taxes	59.3		60.8
Cash Paid (Received) for Transferable Tax Credits	(17.2)		(72.2)
Noncash Acquisitions Under Finance Leases	16.7		20.5
Construction Expenditures Included in Current Liabilities as of June 30,	1,059.1		1,049.9
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,	33.4		8.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

45

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,
	2025	2024	2025	2024
	(in millions of KWhs)
Retail:
Residential	3,275	3,529	6,191	6,058
Commercial	4,719	4,143	8,818	7,450
Industrial	3,300	3,324	6,670	6,597
Miscellaneous	147	156	291	307
Total Retail	11,441	11,152	21,970	20,412

Summary of Heating and Cooling Degree Days

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2025	2024	2025	2024
	(in degree days)
Actual – Heating	4	1	296	162
Normal – Heating	4	3	208	198
Actual – Cooling	992	1,198	1,153	1,344
Normal – Cooling	909	949	1,021	1,086

46

AEP Texas Inc. and Subsidiaries
Reconciliation of 2024 to 2025 Net Income
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2024 Net Income	$	128.4	$	208.1
Changes in Revenues:
Retail Revenues	23.9		81.9
Transmission Revenues	(9.3)		8.0
Other Revenues	(23.0)		(41.7)
Total Change in Revenues	(8.4)		48.2
Changes in Expenses and Other:
Other Operation and Maintenance	(24.5)		(52.1)
Depreciation and Amortization	18.1		25.9
Taxes Other Than Income Taxes	1.6		(4.9)
Interest Income	(1.7)		(2.0)
Allowance for Equity Funds Used During Construction	(3.0)		(0.1)
Non-Service Cost Components of Net Periodic Benefit Cost	1.9		4.0
Interest Expense	(1.4)		(13.0)
Total Change in Expenses and Other	(9.0)		(42.2)
Income Tax Expense	10.1		8.6
2025 Net Income	$	121.1	$	222.7

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Retail Revenues increased $24 million primarily due to the following:

•A $35 million increase in base case and rider revenues.

This increase was partially offset by:

•A $7 million decrease in weather-normalized revenues primarily in the residential class.

•A $4 million decrease in weather-related usage primarily due to a 17% decrease in cooling degree days.

•Transmission Revenues decreased $9 million primarily due to the following:

•A $35 million decrease due to lower peak loads included in the 2025 billing rates.

This decrease was partially offset by:

•A $25 million increase in interim rates driven by increased transmission investments.

•Other Revenues decreased $23 million primarily due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

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

•Other Operation and Maintenance expenses increased $25 million primarily due to the following:

•A $29 million increase in recoverable transmission expenses.

•A $16 million increase in transmission and distribution-related expenses.

These increases were partially offset by:

•A $20 million decrease in employee-related expenses due to the voluntary severance program that occurred in the second quarter of 2024.

47

•Depreciation and Amortization expenses decreased $18 million primarily due to:

•A $16 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

•An $11 million decrease due to the deferral of eligible costs related to HB 5247.

These decreases were partially offset by:

•A $9 million increase due to a higher depreciable base.

•Interest Expense increased $1 million primarily due to the following:

•An $8 million increase due to higher debt balances and interest rates.

•A $5 million increase due to a decrease in capitalization of AFUDC on prepaid pension and OPEB.

These increases were partially offset by:

•A $12 million decrease due to the deferral of eligible costs related to HB 5247.

•Income Tax Expense decreased $10 million primarily due to an increase in amortization of Excess ADIT.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

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

•Retail Revenues increased $82 million primarily due to the following:

•A $76 million increase in base case and rider revenues.

•A $12 million increase in weather-related usage primarily due to an 83% increase in heating degree days.

These increases were partially offset by:

•A $6 million decrease in weather-normalized revenues primarily in the residential class.

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

•A $42 million increase in interim rates driven by increased transmission investments.

This increase was partially offset by:

•A $34 million decrease due to lower peak loads included in the 2025 billing rates.

•Other Revenues decreased $42 million primarily due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

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

•Other Operation and Maintenance expenses increased $52 million primarily due to the following:

•A $42 million increase in recoverable transmission expenses.

•An $18 million increase in transmission and distribution-related expenses.

•A $7 million increase in property and liability insurance expenses.

These increases were partially offset by:

•A $20 million decrease in employee-related expenses due to the voluntary severance program that occurred in the second quarter of 2024.

•Depreciation and Amortization expenses decreased $26 million primarily due to the following:

•A $32 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

•An $11 million decrease due to the deferral of eligible costs related to HB 5247.

These decreases were partially offset by:

•A $19 million increase due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $5 million primarily due to higher property taxes driven by increased investment.

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

•A $19 million increase due to higher debt balances and interest rates.

•A $5 million increase due to a decrease in capitalization of AFUDC on prepaid pension and OPEB.

These increases were partially offset by:

•A $12 million decrease due to the deferral of eligible costs related to HB 5247.

•Income Tax Expense decreased $9 million primarily due to an increase in amortization of Excess ADIT.

48

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
REVENUES
Electric Transmission and Distribution	$	528.3	$	537.7	$	1,048.3	$	1,000.7
Sales to AEP Affiliates	1.4		1.4		2.7		2.7
Other Revenues	1.5		0.5		3.2		2.6
TOTAL REVENUES	531.2		539.6		1,054.2		1,006.0
EXPENSES
Other Operation	163.8		147.8		330.0		288.6
Maintenance	30.2		21.7		54.5		43.8
Depreciation and Amortization	106.8		124.9		215.7		241.6
Taxes Other Than Income Taxes	39.0		40.6		85.5		80.6
TOTAL EXPENSES	339.8		335.0		685.7		654.6
OPERATING INCOME	191.4		204.6		368.5		351.4
Other Income (Expense):
Interest Income	0.4		2.1		0.6		2.6
Allowance for Equity Funds Used During Construction	12.5		15.5		24.0		24.1
Non-Service Cost Components of Net Periodic Benefit Cost	5.3		3.4		11.1		7.1
Interest Expense	(60.7)		(59.3)		(133.8)		(120.8)
INCOME BEFORE INCOME TAX EXPENSE	148.9		166.3		270.4		264.4
Income Tax Expense	27.8		37.9		47.7		56.3
NET INCOME	$	121.1	$	128.4	$	222.7	$	208.1
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

49

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Net Income	$	121.1	$	128.4	$	222.7	$	208.1
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $(0.1) and $0.6 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $(0.1) and $1.6 for the Six Months Ended June 30, 2025 and 2024, Respectively	(0.2)		2.2		(0.4)		6.1
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(0.2)		2.2		(0.4)		6.1
TOTAL COMPREHENSIVE INCOME	$	120.9	$	130.6	$	222.3	$	214.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

50

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2023	$	2,079.6	$	2,725.1	$	(8.6)	$	4,796.1
Net Income			79.7				79.7
Other Comprehensive Income					3.9		3.9
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2024	2,079.6		2,804.8		(4.7)		4,879.7
Capital Contribution from Parent	1.6						1.6
Net Income			128.4				128.4
Other Comprehensive Income					2.2		2.2
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2024	$	2,081.2	$	2,933.2	$	(2.5)	$	5,011.9
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	$	2,092.4	$	2,795.2	$	(3.0)	$	4,884.6
Net Income			101.6				101.6
Other Comprehensive Loss					(0.2)		(0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2025	2,092.4		2,896.8		(3.2)		4,986.0
Capital Contribution from Parent	250.5						250.5
Net Income			121.1				121.1
Other Comprehensive Loss					(0.2)		(0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2025	$	2,342.9	$	3,017.9	$	(3.4)	$	5,357.4
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

51

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2025 and December 31, 2024

(in millions)

(Unaudited)

	June 30,		December 31,
	2025		2024
CURRENT ASSETS
Cash and Cash Equivalents	$	0.1	$	0.1
Restricted Cash (June 30, 2025 and December 31, 2024 Amounts Include $13.3 and $23.5, Respectively, Related to Transition Funding and Restoration Funding)	13.3		23.5
Advances to Affiliates	7.1		7.2
Accounts Receivable:
Customers	200.8		182.8
Affiliated Companies	12.4		10.7
Accrued Unbilled Revenues	108.2		97.2
Miscellaneous	0.1		0.3
Allowance for Credit Losses	(4.1)		(4.3)
Total Accounts Receivable	317.4		286.7
Materials and Supplies	148.6		169.5
Prepayments and Other Current Assets	6.5		13.4
TOTAL CURRENT ASSETS	493.0		500.4
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	7,942.7		7,546.2
Distribution	6,501.1		6,250.5
Other Property, Plant and Equipment	1,198.4		1,175.7
Construction Work in Progress	1,183.6		1,118.0
Total Property, Plant and Equipment	16,825.8		16,090.4
Accumulated Depreciation and Amortization	2,144.3		2,046.9
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	14,681.5		14,043.5
OTHER NONCURRENT ASSETS
Regulatory Assets	383.3		353.6
Securitized Assets (June 30, 2025 and December 31, 2024 Amounts Include $105.1 and $116.7, Respectively, Related to Restoration Funding)	105.1		116.7
Operating Lease Assets	51.0		54.4
Deferred Charges and Other Noncurrent Assets	194.5		131.0
TOTAL OTHER NONCURRENT ASSETS	733.9		655.7
TOTAL ASSETS	$	15,908.4	$	15,199.6
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

52

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2025 and December 31, 2024

(in millions)

(Unaudited)

	June 30,		December 31,
	2025		2024
CURRENT LIABILITIES
Advances from Affiliates	$	109.5	$	284.9
Accounts Payable:
General	318.2		366.2
Affiliated Companies	28.7		34.9
Long-term Debt Due Within One Year – Nonaffiliated (June 30, 2025 and December 31, 2024 Amounts Include $24.7 and $24.4, Respectively, Related to Restoration Funding)	774.7		324.5
Accrued Taxes	141.7		127.1
Accrued Interest (June 30, 2025 and December 31, 2024 Amounts Include $0.9 and $1.9, Respectively, Related to Restoration Funding)	57.4		55.0
Obligations Under Operating Leases	12.8		13.1
Other Current Liabilities	183.0		201.4
TOTAL CURRENT LIABILITIES	1,626.0		1,407.1
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (June 30, 2025 and December 31, 2024 Amounts Include $90.1 and $102.4, Respectively, Related to Restoration Funding)	6,057.6		6,117.1
Deferred Income Taxes	1,378.2		1,322.7
Regulatory Liabilities and Deferred Investment Tax Credits	1,285.6		1,285.4
Obligations Under Operating Leases	40.6		43.4
Deferred Credits and Other Noncurrent Liabilities	163.0		139.3
TOTAL NONCURRENT LIABILITIES	8,925.0		8,907.9
TOTAL LIABILITIES	10,551.0		10,315.0
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Paid-in Capital	2,342.9		2,092.4
Retained Earnings	3,017.9		2,795.2
Accumulated Other Comprehensive Income (Loss)	(3.4)		(3.0)
TOTAL COMMON SHAREHOLDER’S EQUITY	5,357.4		4,884.6
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	15,908.4	$	15,199.6
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

53

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2025		2024
OPERATING ACTIVITIES
Net Income	$	222.7	$	208.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	215.7		241.6
Deferred Income Taxes	36.4		45.1
Allowance for Equity Funds Used During Construction	(24.0)		(24.1)
Pension Contributions to Qualified Plan Trust	(12.0)		—
Property Taxes	(57.9)		(53.5)
Change in Other Noncurrent Assets	(49.9)		(57.0)
Change in Other Noncurrent Liabilities	35.1		19.7
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(30.7)		(73.1)
Materials and Supplies	20.9		5.0
Accounts Payable	2.6		26.0
Accrued Taxes, Net	14.6		43.6
Other Current Assets	8.1		—
Other Current Liabilities	(22.8)		4.7
Net Cash Flows from Operating Activities	358.8		386.1
INVESTING ACTIVITIES
Construction Expenditures	(863.4)		(665.3)
Change in Advances to Affiliates, Net	0.1		(251.1)
Other Investing Activities	32.3		32.8
Net Cash Flows Used for Investing Activities	(831.0)		(883.6)
FINANCING ACTIVITIES
Capital Contribution from Parent	250.5		1.6
Issuance of Long-term Debt – Nonaffiliated	399.8		841.9
Change in Advances from Affiliates, Net	(175.4)		(103.7)
Retirement of Long-term Debt – Nonaffiliated	(12.2)		(244.5)
Principal Payments for Finance Lease Obligations	(3.7)		(3.7)
Other Financing Activities	3.0		1.3
Net Cash Flows from Financing Activities	462.0		492.9
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(10.2)		(4.6)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	23.6		34.1
Cash, Cash Equivalents and Restricted Cash at End of Period	$	13.4	$	29.5
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	124.8	$	111.0
Net Cash Paid (Received) for Income Taxes	(8.4)		(5.4)
Noncash Acquisitions Under Finance Leases	3.9		2.1
Construction Expenditures Included in Current Liabilities as of June 30,	207.1		191.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

54

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,
	2025		2024
	(in millions)
Plant In Service	$	16,089.7	$	14,608.3
Construction Work in Progress	2,105.1		1,914.5
Accumulated Depreciation and Amortization	1,759.6		1,436.8
Total Transmission Property, Net	$	16,435.2	$	15,086.0

AEP Transmission Company, LLC and Subsidiaries
Reconciliation of 2024 to 2025 Net Income
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2024 Earnings Attributable to Common Shareholder	$	175.7	$	356.9
Changes in Transmission Revenues:
Transmission Revenues	266.6		310.9
Total Change in Transmission Revenues	266.6		310.9
Changes in Expenses and Other:
Other Operation and Maintenance	2.8		3.6
Depreciation and Amortization	(12.2)		(20.4)
Taxes Other Than Income Taxes	(0.3)		(1.0)
Interest Income	(2.9)		(4.4)
Allowance for Equity Funds Used During Construction	(1.0)		3.5
Interest Expense	(5.2)		(5.4)
Total Change in Expenses and Other	(18.8)		(24.1)
Income Tax Expense	193.0		184.3
Net Income Attributable to Noncontrolling Interest	(60.7)		(60.7)
2025 Earnings Attributable to Common Shareholder	$	555.8	$	767.3

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Transmission Revenues increased $267 million primarily due to the following:

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

•A $49 million increase due to continued transmission investment.

55

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

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

•Interest Expense increased $5 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense decreased $193 million primarily due to the following:

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

This decrease was partially offset by:

•A $52 million increase due to an increase in pretax book income.

•Net Income Attributable to Noncontrolling Interest increased $61 million due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

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

•Transmission Revenues increased $311 million primarily due to the following:

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

•A $96 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:

•Depreciation and Amortization expenses increased $20 million due to a higher depreciable base.

•Interest Expense increased $5 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense decreased $184 million primarily due to the following:

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

This decrease was partially offset by:

•A $60 million increase due to an increase in pretax book income.

•Net Income Attributable to Noncontrolling Interest increased $61 million due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.

56

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2025		2024		2025		2024
REVENUES
Transmission Revenues	$	110.7	$	97.3	$	216.7	$	195.7
Sales to AEP Affiliates	469.9		394.4		900.1		783.8
(Provision for)/Reversal of – Revenue Refund – Affiliated	127.2		(16.6)		119.8		(22.6)
(Provision for)/ Reversal of – Revenue Refund – Nonaffiliated	33.9		(0.3)		32.2		(1.7)
Other Revenues	0.1		0.4		0.1		2.8
TOTAL REVENUES	741.8		475.2		1,268.9		958.0
EXPENSES
Other Operation	35.8		40.0		64.8		69.9
Maintenance	6.4		5.0		11.8		10.3
Depreciation and Amortization	118.9		106.7		233.0		212.6
Taxes Other Than Income Taxes	75.8		75.5		149.9		148.9
TOTAL EXPENSES	236.9		227.2		459.5		441.7
OPERATING INCOME	504.9		248.0		809.4		516.3
Other Income (Expense):
Interest Income – Affiliated	1.4		4.3		1.8		6.2
Allowance for Equity Funds Used During Construction	21.5		22.5		43.9		40.4
Interest Expense	(56.6)		(51.4)		(111.6)		(106.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	471.2		223.4		743.5		456.7
Income Tax Expense (Benefit)	(145.3)		47.7		(84.5)		99.8
NET INCOME	616.5		175.7		828.0		356.9
Net Income Attributable to Noncontrolling Interest	60.7		—		60.7		—
EARNINGS ATTRIBUTABLE TO AEPTCo COMMON SHAREHOLDER	$	555.8	$	175.7	$	767.3	$	356.9
AEPTCo is wholly-owned by AEP Transmission Holdco.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

57

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

For the Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Paid-in Capital		Retained Earnings		Noncontrolling Interest		Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2023	$	3,043.4	$	3,289.9	$	—	$	6,333.3
Capital Contribution from AEP Member	25.0						25.0
Dividends Paid to AEP Member			(40.0)				(40.0)
Net Income			181.2				181.2
TOTAL MEMBER'S EQUITY – MARCH 31, 2024	3,068.4		3,431.1		—		6,499.5
Capital Contribution from AEP Member	9.6						9.6
Dividends Paid to AEP Member			(31.0)				(31.0)
Net Income			175.7				175.7
TOTAL MEMBER'S EQUITY – JUNE 30, 2024	$	3,078.0	$	3,575.8	$	—	$	6,653.8
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2024	$	3,100.6	$	3,850.3	$	—	$	6,950.9
Capital Contribution from AEP Member	32.5						32.5
Dividends Paid to AEP Member			(42.5)				(42.5)
Net Income			211.5				211.5
TOTAL MEMBER'S EQUITY – MARCH 31, 2025	3,133.1		4,019.3		—		7,152.4
Capital Contribution from AEP Member	8.3						8.3
Dividends Paid to AEP Member			(2,835.8)				(2,835.8)
Midwest Transmission Holdings Noncontrolling Interest Transaction	1,790.5				992.4		2,782.9
Net Income			555.8		60.7		616.5
TOTAL MEMBER'S EQUITY – JUNE 30, 2025	$	4,931.9	$	1,739.3	$	1,053.1	$	7,724.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

58

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2025 and December 31, 2024

(in millions)

(Unaudited)

	June 30,		December 31,
	2025		2024
CURRENT ASSETS
Advances to Affiliates	$	67.9	$	30.4
Accounts Receivable:
Customers	68.7		58.9
Affiliated Companies	170.7		134.1
Miscellaneous	—		1.3
Total Accounts Receivable	239.4		194.3
Prepayments and Other Current Assets	14.9		11.1
TOTAL CURRENT ASSETS	322.2		235.8
TRANSMISSION PROPERTY
Transmission Property	15,544.3		14,913.4
Other Property, Plant and Equipment	545.4		516.1
Construction Work in Progress	2,105.1		1,965.4
Total Transmission Property	18,194.8		17,394.9
Accumulated Depreciation and Amortization	1,759.6		1,578.4
TOTAL TRANSMISSION PROPERTY – NET	16,435.2		15,816.5
OTHER NONCURRENT ASSETS
Regulatory Assets	56.3		0.4
Deferred Property Taxes	177.5		308.9
Deferred Charges and Other Noncurrent Assets	41.6		8.7
TOTAL OTHER NONCURRENT ASSETS	275.4		318.0
TOTAL ASSETS	$	17,032.8	$	16,370.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

59

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

June 30, 2025 and December 31, 2024

(Unaudited)

	June 30,		December 31,
	2025		2024
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	47.7	$	84.7
Accounts Payable:
General	335.9		360.5
Affiliated Companies	107.3		117.0
Long-term Debt Due Within One Year – Nonaffiliated	—		90.0
Accrued Taxes	476.2		665.9
Accrued Interest	47.3		44.9
Obligations Under Operating Leases	1.2		1.3
Other Current Liabilities	44.4		44.5
TOTAL CURRENT LIABILITIES	1,060.0		1,408.8
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	6,098.5		5,678.1
Deferred Income Taxes	1,484.6		1,278.6
Regulatory Liabilities	643.2		878.4
Obligations Under Operating Leases	1.6		1.2
Deferred Credits and Other Noncurrent Liabilities	20.6		174.3
TOTAL NONCURRENT LIABILITIES	8,248.5		8,010.6
TOTAL LIABILITIES	9,308.5		9,419.4
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
MEMBER’S EQUITY
Paid-in Capital	4,931.9		3,100.6
Retained Earnings	1,739.3		3,850.3
TOTAL MEMBER’S EQUITY	6,671.2		6,950.9
Noncontrolling Interest	1,053.1		—
TOTAL EQUITY	7,724.3		6,950.9
TOTAL LIABILITIES AND EQUITY	$	17,032.8	$	16,370.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

60

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2025		2024
OPERATING ACTIVITIES
Net Income	$	828.0	$	356.9
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	233.0		212.6
Deferred Income Taxes	(136.5)		49.4
Allowance for Equity Funds Used During Construction	(43.9)		(40.4)
Property Taxes	131.4		116.2
Change in Other Noncurrent Assets	(44.9)		—
Change in Other Noncurrent Liabilities	(152.3)		(28.9)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(45.1)		(23.8)
Materials and Supplies	—		(0.2)
Accounts Payable	5.3		(6.5)
Accrued Taxes, Net	(201.9)		(65.3)
Other Current Assets	7.9		0.5
Other Current Liabilities	(15.7)		2.6
Net Cash Flows from Operating Activities	565.3		573.1
INVESTING ACTIVITIES
Construction Expenditures	(786.9)		(657.8)
Change in Advances to Affiliates, Net	(37.5)		(208.1)
Other Investing Activities	21.7		11.3
Net Cash Flows Used for Investing Activities	(802.7)		(854.6)
FINANCING ACTIVITIES
Capital Contribution from Member	40.8		34.6
Issuance of Long-term Debt – Nonaffiliated	419.0		445.7
Retirement of Long-term Debt – Nonaffiliated	(90.0)		—
Change in Advances from Affiliates, Net	(37.0)		(127.8)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	2,782.9		—
Dividends Paid to Member	(2,878.3)		(71.0)
Net Cash Flows from Financing Activities	237.4		281.5
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	$	106.7	$	96.9
Net Cash Paid (Received) for Income Taxes	(21.1)		(12.5)
Construction Expenditures Included in Current Liabilities as of June 30,	218.9		237.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

61

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,
	2025	2024	2025	2024
	(in millions of KWhs)
Retail:
Residential	2,032	2,085	5,686	5,350
Commercial	1,465	1,454	2,965	2,929
Industrial	2,204	2,203	4,280	4,305
Miscellaneous	208	203	419	414
Total Retail	5,909	5,945	13,350	12,998
Wholesale (a)	576	564	1,303	1,218
Total KWhs	6,485	6,509	14,653	14,216

(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,
	2025	2024	2025	2024
	(in degree days)
Actual – Heating	69	48	1,433	1,029
Normal – Heating	80	85	1,359	1,395
Actual – Cooling	417	535	428	537
Normal – Cooling	387	378	393	384

62

Appalachian Power Company and Subsidiaries
Reconciliation of 2024 to 2025 Net Income
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2024 Net Income	$	58.3	$	194.8
Changes in Revenues:
Retail Revenues	20.0		106.7
Off-system Sales	0.7		1.2
Transmission Revenues	14.3		15.6
Other Revenues	2.4		(6.2)
Total Change in Revenues	37.4		117.3
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	14.0		3.6
Other Operation and Maintenance	(4.9)		(12.2)
Depreciation and Amortization	(25.1)		(38.3)
Taxes Other Than Income Taxes	3.4		8.9
Interest Income	0.5		0.7
Allowance for Equity Funds Used During Construction	(0.1)		1.4
Non-Service Cost Components of Net Periodic Benefit Cost	(1.1)		(3.0)
Interest Expense	(1.9)		(1.4)
Total Change in Expenses and Other	(15.2)		(40.3)
Income Tax Expense	26.4		(0.3)
2025 Net Income	$	106.9	$	271.5

Second Quarter of 2025 Compared to Second Quarter of 2024

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

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

•A $10 million increase in fuel revenues.

•A $7 million increase in weather-normalized margins primarily in the residential and commercial classes.

•A $7 million increase in rider revenues.

These increases were partially offset by:

•A $7 million decrease in weather-related usage primarily due to a 22% decrease in cooling degree days.

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

•A $10 million increase due to continued transmission investment.

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

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 impact to the West Virginia ENEC as a result of the June 2025 FERC NOLC order.

•Other Operation and Maintenance expenses increased $5 million primarily due to the following:

•A $24 million increase in transmission expenses primarily due to:

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

•A $5 million increase in recoverable expenses.

•A $5 million increase in vegetation management expenses.

•A $6 million increase due to recoverable energy assistance program expenses for qualified Virginia customers.

63

These increases were partially offset by:

•A $23 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.

•Depreciation and Amortization expenses increased $25 million primarily due to a higher depreciable base.

•Income Tax Expense decreased $26 million primarily 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.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

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

•Retail Revenues increased $107 million primarily due to the following:

•A $35 million increase in fuel revenues.

•A $34 million increase in weather-related usage primarily due to a 39% increase in heating degree days, partially offset by a 20% decrease in cooling degree days.

•A $30 million increase in rider revenues.

•Transmission Revenues increased $16 million primarily due to the following:

•A $12 million increase due to continued transmission investment.

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

•Other Revenues decreased $6 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 $4 million primarily due to the following:

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

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

These decreases were partially offset by:

•A $27 million increase in load and purchased power prices as well as an increase in West Virginia ENEC rates resulting in higher amortization of deferred fuel regulatory assets.

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

•A $27 million increase in transmission expenses primarily due to:

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

•A $7 million increase in recoverable expenses.

•A $5 million increase in vegetation management and Virginia storm-related expenses.

•A $14 million increase due to recoverable energy assistance program expenses for qualified Virginia customers.

These increases were partially offset by:

•A $25 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.

•Depreciation and Amortization expenses increased $38 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes decreased $9 million primarily due to lower business and occupation taxes.

•Income Tax Expense remained consistent primarily due to the following:

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

•A $13 million increase due to a decrease in amortization of Excess ADIT.

These increases were partially offset by:

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

•A $5 million decrease due to an increase in flow-through cost of removal.

64

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2025		2024		2025		2024
REVENUES
Electric Generation, Transmission and Distribution	$	876.2	$	851.7	$	1,973.7	$	1,876.0
Sales to AEP Affiliates	66.2		54.8		138.2		117.9
Other Revenues	5.2		3.7		8.6		9.3
TOTAL REVENUES	947.6		910.2		2,120.5		2,003.2
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	290.8		304.8		698.0		701.6
Other Operation	210.8		212.0		433.0		424.6
Maintenance	84.4		78.3		162.1		158.3
Depreciation and Amortization	170.8		145.7		333.8		295.5
Taxes Other Than Income Taxes	38.8		42.2		79.3		88.2
TOTAL EXPENSES	795.6		783.0		1,706.2		1,668.2
OPERATING INCOME	152.0		127.2		414.3		335.0
Other Income (Expense):
Interest Income	1.7		1.2		2.7		2.0
Allowance for Equity Funds Used During Construction	4.2		4.3		8.6		7.2
Non-Service Cost Components of Net Periodic Benefit Cost	5.3		6.4		10.5		13.5
Interest Expense	(70.0)		(68.1)		(137.6)		(136.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	93.2		71.0		298.5		221.5
Income Tax Expense (Benefit)	(13.7)		12.7		27.0		26.7
NET INCOME	$	106.9	$	58.3	$	271.5	$	194.8
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

65

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2025		2024		2025		2024
Net Income	$	106.9	$	58.3	$	271.5	$	194.8
OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $(0.1) and $(0.1) for the Six Months Ended June 30, 2025 and 2024, Respectively	(0.2)		(0.2)		(0.4)		(0.4)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $0 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $(0.1) and $(0.1) for the Six Months Ended June 30, 2025 and 2024, Respectively	(0.1)		(0.3)		(0.2)		(0.6)
TOTAL OTHER COMPREHENSIVE LOSS	(0.3)		(0.5)		(0.6)		(1.0)
TOTAL COMPREHENSIVE INCOME	$	106.6	$	57.8	$	270.9	$	193.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

66

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2023	$	260.4	$	1,834.5	$	3,185.5	$	(3.7)	$	5,276.7
Capital Contribution from Parent			100.0						100.0
Net Income					136.5				136.5
Other Comprehensive Loss							(0.5)		(0.5)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2024	260.4		1,934.5		3,322.0		(4.2)		5,512.7
Capital Contribution from Parent			9.5						9.5
Net Income					58.3				58.3
Other Comprehensive Loss							(0.5)		(0.5)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2024	$	260.4	$	1,944.0	$	3,380.3	$	(4.7)	$	5,580.0
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2024	$	260.4	$	1,944.1	$	3,532.2	$	11.3	$	5,748.0
Common Stock Dividends					(50.0)				(50.0)
Net Income					164.6				164.6
Other Comprehensive Loss							(0.3)		(0.3)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2025	260.4		1,944.1		3,646.8		11.0		5,862.3
Capital Contribution from Parent			7.2						7.2
Net Income					106.9				106.9
Other Comprehensive Loss							(0.3)		(0.3)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2025	$	260.4	$	1,951.3	$	3,753.7	$	10.7	$	5,976.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

67

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2025 and December 31, 2024

(in millions)

(Unaudited)

	June 30,		December 31,
	2025		2024
CURRENT ASSETS
Cash and Cash Equivalents	$	6.2	$	3.9
Restricted Cash for Securitized Funding	18.2		16.2
Advances to Affiliates	18.1		17.7
Accounts Receivable:
Customers	192.7		185.7
Affiliated Companies	114.5		110.5
Accrued Unbilled Revenues	76.0		93.1
Miscellaneous	0.9		0.3
Allowance for Credit Losses	(2.2)		(2.0)
Total Accounts Receivable	381.9		387.6
Fuel	267.8		308.0
Materials and Supplies	133.9		131.7
Risk Management Assets	108.7		35.7
Regulatory Asset for Under-Recovered Fuel Costs	128.3		148.1
Prepayments and Other Current Assets	25.0		46.0
TOTAL CURRENT ASSETS	1,088.1		1,094.9
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	7,257.8		7,272.6
Transmission	5,106.1		5,001.5
Distribution	5,762.6		5,568.5
Other Property, Plant and Equipment	1,145.5		1,062.9
Construction Work in Progress	775.1		742.6
Total Property, Plant and Equipment	20,047.1		19,648.1
Accumulated Depreciation and Amortization	6,212.0		6,035.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	13,835.1		13,612.5
OTHER NONCURRENT ASSETS
Regulatory Assets	1,451.3		1,366.0
Securitized Assets	92.2		106.2
Employee Benefits and Pension Assets	211.8		203.9
Operating Lease Assets	69.1		67.0
Deferred Charges and Other Noncurrent Assets	174.4		215.4
TOTAL OTHER NONCURRENT ASSETS	1,998.8		1,958.5
TOTAL ASSETS	$	16,922.0	$	16,665.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

68

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2025 and December 31, 2024

(Unaudited)

	June 30,		December 31,
	2025		2024
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	172.9	$	95.0
Accounts Payable:
General	392.6		427.2
Affiliated Companies	136.7		205.9
Long-term Debt Due Within One Year – Nonaffiliated	271.1		798.6
Customer Deposits	98.8		86.6
Accrued Taxes	127.9		168.8
Obligations Under Operating Leases	14.9		13.7
Other Current Liabilities	181.0		229.7
TOTAL CURRENT LIABILITIES	1,395.9		2,025.5
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	5,500.9		4,861.7
Deferred Income Taxes	2,079.8		2,033.5
Regulatory Liabilities and Deferred Investment Tax Credits	1,070.1		1,115.8
Asset Retirement Obligations	785.1		767.4
Employee Benefits and Pension Obligations	28.0		29.6
Obligations Under Operating Leases	54.7		54.0
Deferred Credits and Other Noncurrent Liabilities	31.4		30.4
TOTAL NONCURRENT LIABILITIES	9,550.0		8,892.4
TOTAL LIABILITIES	10,945.9		10,917.9
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares
Outstanding – 13,499,500 Shares	260.4		260.4
Paid-in Capital	1,951.3		1,944.1
Retained Earnings	3,753.7		3,532.2
Accumulated Other Comprehensive Income (Loss)	10.7		11.3
TOTAL COMMON SHAREHOLDER’S EQUITY	5,976.1		5,748.0
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	16,922.0	$	16,665.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

69

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2025		2024
OPERATING ACTIVITIES
Net Income	$	271.5	$	194.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	333.8		295.5
Deferred Income Taxes	(4.5)		(27.4)
Allowance for Equity Funds Used During Construction	(8.6)		(7.2)
Mark-to-Market of Risk Management Contracts	(72.6)		(54.4)
Deferred Fuel Over/Under-Recovery, Net	6.4		81.2
Change in Regulatory Assets	(117.6)		1.2
Change in Other Noncurrent Assets	28.5		(0.7)
Change in Other Noncurrent Liabilities	6.4		5.9
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	5.7		(32.2)
Fuel, Materials and Supplies	38.0		45.4
Margin Deposits	17.9		(12.4)
Accounts Payable	(60.9)		66.4
Accrued Taxes, Net	(38.6)		41.6
Other Current Assets	(0.1)		2.3
Other Current Liabilities	(19.1)		10.8
Net Cash Flows from Operating Activities	386.2		610.8
INVESTING ACTIVITIES
Construction Expenditures	(527.6)		(443.5)
Change in Advances to Affiliates, Net	(0.4)		(23.6)
Other Investing Activities	4.0		9.1
Net Cash Flows Used for Investing Activities	(524.0)		(458.0)
FINANCING ACTIVITIES
Capital Contribution from Parent	7.2		109.5
Issuance of Long-term Debt – Nonaffiliated	528.2		480.8
Change in Advances from Affiliates, Net	77.9		(339.6)
Retirement of Long-term Debt – Nonaffiliated	(418.4)		(399.5)
Principal Payments for Finance Lease Obligations	(4.3)		(4.4)
Dividends Paid on Common Stock	(50.0)		—
Other Financing Activities	1.5		0.4
Net Cash Flows from (Used for) Financing Activities	142.1		(152.8)
Net Increase in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	4.3		—
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	20.1		19.9
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	24.4	$	19.9
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	134.4	$	126.6
Net Cash Paid (Received) for Income Taxes	(18.5)		9.6
Cash Paid (Received) for Transferable Tax Credits	—		(0.1)
Noncash Acquisitions Under Finance Leases	2.2		0.7
Construction Expenditures Included in Current Liabilities as of June 30,	115.4		143.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

70

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,
	2025	2024	2025	2024
	(in millions of KWhs)
Retail:
Residential	1,097	1,162	2,650	2,600
Commercial	1,414	1,290	2,686	2,565
Industrial	1,856	1,853	3,604	3,661
Miscellaneous	9	11	22	25
Total Retail	4,376	4,316	8,962	8,851
Wholesale (a)	1,507	1,117	3,943	2,737
Total KWhs	5,883	5,433	12,905	11,588

(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,
	2025	2024	2025	2024
	(in degree days)
Actual – Heating	217	141	2,335	1,826
Normal – Heating	237	241	2,365	2,422
Actual – Cooling	280	357	280	357
Normal – Cooling	284	268	285	269

71

Indiana Michigan Power Company and Subsidiaries
Reconciliation of 2024 to 2025 Net Income
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2024 Net Income	$	35.2	$	180.2
Changes in Revenues:
Retail Revenues	82.7		133.4
Off-system Sales	56.8		62.6
Transmission Revenues	9.9		10.7
Other Revenues	(6.5)		(9.0)
Total Change in Revenues	142.9		197.7
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(46.3)		(99.5)
Purchased Electricity from AEP Affiliates	(21.9)		(36.4)
Other Operation and Maintenance	(11.8)		(12.2)
Asset Impairments and Other Related Charges	13.4		13.4
Depreciation and Amortization	(10.4)		(26.1)
Taxes Other Than Income Taxes	3.0		0.1
Other Income	0.6		2.0
Non-Service Cost Components of Net Periodic Benefit Cost	(1.3)		(2.8)
Interest Expense	(1.9)		(10.5)
Total Change in Expenses and Other	(76.6)		(172.0)
Income Tax Benefit	22.6		(24.3)
2025 Net Income	$	124.1	$	181.6

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Retail Revenues increased $83 million primarily due to the following:

•A $35 million increase due to the implementation of new base rates in Indiana and Michigan.

•A $34 million increase in weather-normalized margins primarily in the commercial class.

•A $23 million increase in rider revenues.

•A $20 million increase in fuel revenues.

These increases were partially offset by:

•A $22 million decrease due to regulatory provisions for refund.

•A $6 million decrease in weather-related usage primarily due to a 21% decrease in cooling degree days.

•Off-system Sales increased $57 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales.

•Transmission Revenues increased $10 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 Benefit changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $46 million primarily due to an increase in recoverable fuel and purchased power costs and an increase in Rockport Plant, Unit 2 merchant generation fuel costs.

•Purchased Electricity from AEP Affiliates increased $22 million primarily due to an increase in purchased electricity from AEGCo.

72

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

•A $21 million increase in vegetation management expenses.

•A $6 million increase in nuclear expenses at Cook Plant.

These increases were partially offset by:

•A $12 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.

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

•Asset Impairments and Other Related Charges decreased $13 million due to the Federal EPA’s revised CCR rules finalized in 2024.

•Depreciation and Amortization expenses increased $10 million primarily due to the following:

•A $5 million increase due to a higher depreciable base.

•A $3 million increase in regulatory reserves related to Nuclear PTCs.

•Income Tax Benefit increased $23 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 NOLCs in transmission formula rates.

•An $18 million increase due to an increase in deferred ITC amortization and PTCs.

These increases were partially offset by:

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

•A $13 million decrease in amortization of Excess ADIT.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

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

•Retail Revenues increased $133 million primarily due to the following:

•A $78 million increase due to the implementation of new base rates in Indiana and Michigan.

•A $61 million increase in fuel revenues.

•A $35 million increase in weather-normalized margins primarily in the residential and commercial classes, partially offset by a decrease in the industrial class.

•A $16 million increase in rider revenues.

•A $7 million increase in weather-related usage primarily due to a 28% increase in heating degree days.

These increases were partially offset by:

•A $71 million decrease due to regulatory provisions for refund.

•Off-system Sales increased $63 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales.

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

•Other Revenues decreased $9 million primarily due to the following:

•A $6 million decrease in RTD barging revenues.

•A $4 million decrease in sales of renewable energy credits.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $100 million primarily due to an increase in recoverable fuel and purchased power costs and an increase in Rockport Plant, Unit 2, merchant generation fuel costs, partially offset by a decrease due to a prior year purchased power disallowance from the MPSC order on the 2021 PSCR reconciliation.

•Purchased Electricity from AEP Affiliates increased $36 million primarily due to an increase in purchased electricity from AEGCo.

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

•A $28 million increase in distribution expenses primarily due to an increase in vegetation management costs.

•A $7 million increase in transmission expenses primarily due to an $11 million increase in recoverable PJM expenses, partially offset by a $5 million decrease primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

These increases were partially offset by:

•A $13 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.

•A $12 million decrease in demand side management expenses.

73

•Asset Impairments and Other Related Charges decreased $13 million due to the Federal EPA’s revised CCR rules finalized in 2024.

•Depreciation and Amortization expenses increased $26 million primarily due to the following:

•A $9 million increase due to a higher depreciable base.

•A $9 million increase due to a prior year deferral of Excess ADIT as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs.

•A $5 million increase in regulatory reserves related to Nuclear PTCs.

•Interest Expense increased $11 million primarily 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.

•Income Tax Benefit decreased $24 million primarily due to the following:

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

•A $17 million decrease in amortization of Excess ADIT.

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

These decreases were partially offset by:

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

•A $24 million increase due to an increase in PTCs.

74

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2025		2024		2025		2024
REVENUES
Electric Generation, Transmission and Distribution	$	735.6	$	574.9	$	1,494.7	$	1,232.3
Sales to AEP Affiliates	1.5		5.4		5.4		7.7
(Provision for)/Reversal of – Revenue Refund – Affiliated	9.2		(3.3)		8.5		(3.8)
Provision for Refund – Nonaffiliated	(25.7)		(5.3)		(83.9)		(14.9)
Other Revenues – Affiliated	14.4		20.5		29.9		35.5
Other Revenues – Nonaffiliated	2.2		2.1		4.8		4.9
TOTAL REVENUES	737.2		594.3		1,459.4		1,261.7
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	132.4		86.1		308.2		208.7
Purchased Electricity from AEP Affiliates	66.4		44.5		142.4		106.0
Other Operation	177.5		190.3		348.4		368.5
Maintenance	87.8		63.2		147.9		115.6
Asset Impairments and Other Related Charges	—		13.4		—		13.4
Depreciation and Amortization	128.7		118.3		252.7		226.6
Taxes Other Than Income Taxes	21.6		24.6		47.8		47.9
TOTAL EXPENSES	614.4		540.4		1,247.4		1,086.7
OPERATING INCOME	122.8		53.9		212.0		175.0
Other Income (Expense):
Other Income	3.8		3.2		8.4		6.4
Non-Service Cost Components of Net Periodic Benefit Cost	5.2		6.5		10.4		13.2
Interest Expense	(38.9)		(37.0)		(73.7)		(63.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	92.9		26.6		157.1		131.4
Income Tax Expense (Benefit)	(31.2)		(8.6)		(24.5)		(48.8)
NET INCOME	$	124.1	$	35.2	$	181.6	$	180.2
The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

75

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2025		2024		2025		2024
Net Income	$	124.1	$	35.2	$	181.6	$	180.2
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $0.1 and $0.1 for the Six Months Ended June 30, 2025 and 2024, Respectively	0.1		0.1		0.2		0.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $0 and $0 for the Six Months Ended June 30, 2025 and 2024, Respectively	0.1		(0.1)		0.1		(0.1)
TOTAL OTHER COMPREHENSIVE INCOME	0.2		—		0.3		0.1
TOTAL COMPREHENSIVE INCOME	$	124.3	$	35.2	$	181.9	$	180.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

76

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2023	$	56.6	$	997.6	$	2,086.6	$	(0.6)	$	3,140.2
Common Stock Dividends					(37.5)				(37.5)
Net Income					145.0				145.0
Other Comprehensive Income							0.1		0.1
TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 2024	56.6		997.6		2,194.1		(0.5)		3,247.8
Capital Contribution from Parent			5.0						5.0
Common Stock Dividends					(37.5)				(37.5)
Net Income					35.2				35.2
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2024	$	56.6	$	1,002.6	$	2,191.8	$	(0.5)	$	3,250.5
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2024	$	56.6	$	1,011.7	$	2,328.0	$	0.2	$	3,396.5
Common Stock Dividends					(50.0)				(50.0)
Net Income					57.5				57.5
Other Comprehensive Income							0.1		0.1
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2025	56.6		1,011.7		2,335.5		0.3		3,404.1
Capital Contribution from Parent			7.4						7.4
Net Income					124.1				124.1
Other Comprehensive Income							0.2		0.2
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2025	$	56.6	$	1,019.1	$	2,459.6	$	0.5	$	3,535.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

77

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2025 and December 31, 2024

(in millions)

(Unaudited)

	June 30,		December 31,
	2025		2024
CURRENT ASSETS
Cash and Cash Equivalents	$	3.5	$	1.5
Accounts Receivable:
Customers	62.6		58.7
Affiliated Companies	81.6		79.1
Accrued Unbilled Revenues	25.5		21.4
Miscellaneous	5.3		6.3
Total Accounts Receivable	175.0		165.5
Fuel	54.6		83.4
Materials and Supplies	214.9		212.2
Risk Management Assets	12.3		18.4
Regulatory Asset for Under-Recovered Fuel Costs	5.0		10.6
Prepayments and Other Current Assets	60.2		52.0
TOTAL CURRENT ASSETS	525.5		543.6
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	5,460.1		5,503.0
Transmission	1,978.1		1,957.8
Distribution	3,692.0		3,535.0
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	1,062.9		992.4
Construction Work in Progress	390.1		334.9
Total Property, Plant and Equipment	12,583.2		12,323.1
Accumulated Depreciation, Depletion and Amortization	4,786.8		4,643.8
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	7,796.4		7,679.3
OTHER NONCURRENT ASSETS
Regulatory Assets	616.1		548.1
Spent Nuclear Fuel and Decommissioning Trusts	4,609.7		4,395.1
Operating Lease Assets	59.0		51.5
Deferred Charges and Other Noncurrent Assets	290.1		317.9
TOTAL OTHER NONCURRENT ASSETS	5,574.9		5,312.6
TOTAL ASSETS	$	13,896.8	$	13,535.5
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

78

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2025 and December 31, 2024

(dollars in millions)

(Unaudited)

	June 30,		December 31,
	2025		2024
CURRENT LIABILITIES
Advances from Affiliates	$	25.7	$	126.8
Accounts Payable:
General	250.3		202.2
Affiliated Companies	94.3		98.5
Long-term Debt Due Within One Year – Nonaffiliated    (June 30, 2025 and December 31, 2024 Amounts Include $94.6 and $79.0,    Respectively, Related to DCC Fuel)	94.6		269.2
Customer Deposits	54.6		59.1
Accrued Taxes	101.5		102.2
Accrued Interest	41.6		41.3
Obligations Under Operating Leases	14.9		12.3
Regulatory Liability for Over-Recovered Fuel Costs	13.5		10.3
Other Current Liabilities	162.9		149.3
TOTAL CURRENT LIABILITIES	853.9		1,071.2
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,416.3		3,225.1
Deferred Income Taxes	1,185.1		1,175.8
Regulatory Liabilities and Deferred Investment Tax Credits	2,636.3		2,480.8
Asset Retirement Obligations	2,135.0		2,088.8
Obligations Under Operating Leases	45.0		40.1
Deferred Credits and Other Noncurrent Liabilities	89.4		57.2
TOTAL NONCURRENT LIABILITIES	9,507.1		9,067.8
TOTAL LIABILITIES	10,361.0		10,139.0
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 2,500,000 Shares
Outstanding – 1,400,000 Shares	56.6		56.6
Paid-in Capital	1,019.1		1,011.7
Retained Earnings	2,459.6		2,328.0
Accumulated Other Comprehensive Income (Loss)	0.5		0.2
TOTAL COMMON SHAREHOLDER’S EQUITY	3,535.8		3,396.5
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	13,896.8	$	13,535.5
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

79

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2025		2024
OPERATING ACTIVITIES
Net Income	$	181.6	$	180.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	252.7		226.6
Deferred Income Taxes	(45.7)		(69.8)
Deferral of Incremental Nuclear Refueling Outage Expenses, Net	(22.8)		(20.5)
Asset Impairments and Other Related Charges	—		13.4
Allowance for Equity Funds Used During Construction	(8.1)		(6.7)
Mark-to-Market of Risk Management Contracts	6.6		9.5
Amortization of Nuclear Fuel	51.8		46.1
Deferred Fuel Over/Under-Recovery, Net	8.8		(9.5)
Change in Other Noncurrent Assets	(13.9)		10.2
Change in Other Noncurrent Liabilities	55.3		29.3
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(9.5)		(0.1)
Fuel, Materials and Supplies	26.1		8.6
Accounts Payable	27.8		(7.5)
Accrued Taxes, Net	(0.7)		36.1
Other Current Assets	2.5		(8.8)
Other Current Liabilities	(13.6)		(10.8)
Net Cash Flows from Operating Activities	498.9		426.3
INVESTING ACTIVITIES
Construction Expenditures	(305.7)		(275.0)
Purchases of Investment Securities	(1,330.0)		(1,187.1)
Sales of Investment Securities	1,294.4		1,154.1
Acquisitions of Nuclear Fuel	(45.6)		(69.8)
Other Investing Activities	27.2		3.7
Net Cash Flows Used for Investing Activities	(359.7)		(374.1)
FINANCING ACTIVITIES
Capital Contribution from Parent	7.4		5.0
Issuance of Long-term Debt – Nonaffiliated	249.0		80.4
Change in Advances from Affiliates, Net	(101.1)		(10.7)
Retirement of Long-term Debt – Nonaffiliated	(240.0)		(48.6)
Principal Payments for Finance Lease Obligations	(3.1)		(3.6)
Dividends Paid on Common Stock	(50.0)		(75.0)
Other Financing Activities	0.6		0.6
Net Cash Flows Used for Financing Activities	(137.2)		(51.9)
Net Increase in Cash and Cash Equivalents	2.0		0.3
Cash and Cash Equivalents at Beginning of Period	1.5		2.1
Cash and Cash Equivalents at End of Period	$	3.5	$	2.4
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	71.5	$	72.8
Net Cash Paid (Received) for Income Taxes	2.9		(14.5)
Noncash Acquisitions Under Finance Leases	1.4		1.0
Construction Expenditures Included in Current Liabilities as of June 30,	81.8		86.2
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,	33.4		8.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

80

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,
	2025	2024	2025	2024
	(in millions of KWhs)
Retail:
Residential	3,024	3,064	7,119	6,815
Commercial	6,323	5,066	11,812	9,750
Industrial	3,748	3,502	7,134	7,041
Miscellaneous	25	24	53	53
Total Retail (a)	13,120	11,656	26,118	23,659
Wholesale (b)	464	253	1,131	843
Total KWhs	13,584	11,909	27,249	24,502

(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,
	2025	2024	2025	2024
	(in degree days)
Actual – Heating	170	110	2,077	1,573
Normal – Heating	173	181	1,993	2,052
Actual – Cooling	336	422	342	422
Normal – Cooling	323	306	325	309

81

Ohio Power Company and Subsidiaries
Reconciliation of 2024 to 2025 Net Income
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2024 Net Income	$	18.4	$	89.0
Changes in Revenues:
Retail Revenues	14.3		(17.5)
Off-system Sales	12.9		25.8
Transmission Revenues	3.1		6.2
Other Revenues	(7.6)		(12.1)
Total Change in Revenues	22.7		2.4
Changes in Expenses and Other:
Purchased Electricity for Resale	(3.9)		7.9
Purchased Electricity from AEP Affiliates	10.7		41.4
Other Operation and Maintenance	4.6		(27.2)
Asset Impairments and Other Related Charges	52.9		52.9
Depreciation and Amortization	7.2		19.1
Taxes Other Than Income Taxes	17.0		9.1
Other Income	(0.9)		—
Allowance for Equity Funds Used During Construction	2.8		4.3
Non-Service Cost Components of Net Periodic Benefit Cost	(1.0)		(2.2)
Interest Expense	(3.0)		(6.8)
Total Change in Expenses and Other	86.4		98.5
Income Tax Expense	(25.6)		(26.3)
Equity Earnings of Unconsolidated Subsidiaries	0.9		2.2
2025 Net Income	$	102.8	$	165.8

Second Quarter of 2025 Compared to Second Quarter of 2024

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

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

•A $24 million increase in weather-normalized revenues primarily in the commercial and industrial classes.

•An $8 million increase in rider revenues.

These increases were partially offset by:

•An $11 million decrease due to lower prices and lower customer participation in OPCo’s SSO.

•A $5 million decrease in weather-related usage driven by a 20% decrease in cooling degree days.

•Off-system Sales increased $13 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.

•Other Revenues decreased $8 million primarily due to lower third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

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

•Purchased Electricity from AEP Affiliates expenses decreased $11 million primarily due to decreased recoverable purchases to serve SSO customers.

82

•Other Operation and Maintenance expenses decreased $5 million primarily due to the following:

•A $13 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.

•A $9 million decrease related to recoverable energy assistance program expenses for qualified Ohio customers.

These decreases were partially offset by:

•An $8 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•An $8 million increase in distribution expenses primarily related to recoverable storm restoration costs and recoverable vegetation management expenses.

•Asset Impairments and Other Related Charges decreased $53 million primarily due to the Federal EPA’s revised CCR rules finalized in 2024.

•Depreciation and Amortization expenses decreased $7 million primarily due to capital rider under-recoveries.

•Taxes Other Than Income Taxes decreased $17 million primarily due to the following:

•A $12 million decrease in property taxes.

•A $6 million decrease in state excise taxes due to decreased billed KWhs in 2025.

•Income Tax Expense increased $26 million primarily due to an increase in pretax book income.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024

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

•Retail Revenues decreased $18 million primarily due to the following:

•An $88 million decrease due to lower prices and lower customer participation in OPCo’s SSO.

•A $4 million decrease in weather-normalized revenues primarily in the residential class partially offset by an increase in the commercial class.

These decreases were partially offset by:

•A $57 million increase in rider revenues.

•A $22 million increase in weather-related usage driven by a 32% increase in heating degree days.

•Off-system Sales increased $26 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.

•Transmission Revenues increased $6 million primarily due to continued transmission investment.

•Other Revenues decreased $12 million primarily due to the following:

•A $7 million decrease in recoverable sales of renewable energy credits.

•A $5 million decrease due to lower third-party Legacy Generation Resource Rider revenue 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 $8 million primarily due to the following:

•A $41 million decrease in recoverable auction purchases primarily due to lower prices.

•A $12 million decrease in recoverable alternative energy rider expenses.

These decreases were partially offset by:

•A $30 million estimated reduction in regulatory assets for OVEC-related purchased power costs that are no longer probable of future recovery due to recently approved legislation in Ohio.

•A $17 million increase in recoverable OVEC costs.

•Purchased Electricity from AEP Affiliates expenses decreased $41 million primarily due to decreased recoverable purchases to serve SSO customers.

•Other Operation and Maintenance expenses increased $27 million primarily due to the following:

•A $58 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

This increase was partially offset by:

•A $19 million decrease related to recoverable energy assistance program expenses for qualified Ohio customers.

•A $12 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.

•Asset Impairments and Other Related Charges decreased $53 million primarily due to the Federal EPA’s revised CCR rules finalized in 2024.

•Depreciation and Amortization expenses decreased $19 million primarily due to capital rider under-recoveries.

•Taxes Other Than Income Taxes decreased $9 million primarily due to lower property taxes.

•Interest Expense increased $7 million primarily due to higher debt balances.

•Income Tax Expense increased $26 million primarily due to an increase in pretax book income.

83

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2025		2024		2025		2024
REVENUES
Electricity, Transmission and Distribution	$	910.1	$	887.8	$	1,900.3	$	1,903.2
Sales to AEP Affiliates	6.3		5.7		16.0		11.4
Other Revenues	2.6		2.8		6.2		5.5
TOTAL REVENUES	919.0		896.3		1,922.5		1,920.1
EXPENSES
Purchased Electricity for Resale	188.9		185.0		435.8		443.7
Purchased Electricity from AEP Affiliates	14.8		25.5		30.7		72.1
Other Operation	283.3		283.8		617.0		577.0
Maintenance	63.0		67.1		115.6		128.4
Asset Impairments and Other Related Charges	—		52.9		—		52.9
Depreciation and Amortization	94.8		102.0		188.7		207.8
Taxes Other Than Income Taxes	120.3		137.3		279.0		288.1
TOTAL EXPENSES	765.1		853.6		1,666.8		1,770.0
OPERATING INCOME	153.9		42.7		255.7		150.1
Other Income (Expense):
Other Income	—		0.9		0.9		0.9
Allowance for Equity Funds Used During Construction	7.1		4.3		14.1		9.8
Non-Service Cost Components of Net Periodic Benefit Cost	4.3		5.3		8.6		10.8
Interest Expense	(39.6)		(36.6)		(78.0)		(71.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	125.7		16.6		201.3		100.4
Income Tax Expense (Benefit)	23.0		(2.6)		36.9		10.6
Equity Earnings of Unconsolidated Subsidiaries	0.1		(0.8)		1.4		(0.8)
NET INCOME	$	102.8	$	18.4	$	165.8	$	89.0
The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

84

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2023	$	321.2	$	1,012.8	$	2,237.3	$	3,571.3
Net Income					70.6		70.6
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2024	321.2		1,012.8		2,307.9		3,641.9
Net Income					18.4		18.4
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2024	$	321.2	$	1,012.8	$	2,326.3	$	3,660.3
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	$	321.2	$	1,020.0	$	2,542.9	$	3,884.1
Common Stock Dividends					(46.0)		(46.0)
Net Income					63.0		63.0
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2025	321.2		1,020.0		2,559.9		3,901.1
Capital Contribution from Parent			1.8				1.8
Common Stock Dividends					(25.0)		(25.0)
Net Income					102.8		102.8
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2025	$	321.2	$	1,021.8	$	2,637.7	$	3,980.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

85

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2025 and December 31, 2024

(in millions)

(Unaudited)

	June 30,		December 31,
	2025		2024
CURRENT ASSETS
Cash and Cash Equivalents	$	8.2	$	4.5
Advances to Affiliates	—		114.9
Accounts Receivable:
Customers	167.3		189.2
Affiliated Companies	120.8		117.5
Accrued Unbilled Revenues	51.2		31.1
Miscellaneous	4.7		8.6
Total Accounts Receivable	344.0		346.4
Materials and Supplies	177.7		141.4
Prepayments and Other Current Assets	12.1		19.9
TOTAL CURRENT ASSETS	542.0		627.1
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	3,744.8		3,663.9
Distribution	7,389.7		7,244.0
Other Property, Plant and Equipment	1,258.6		1,256.0
Construction Work in Progress	818.9		691.1
Total Property, Plant and Equipment	13,212.0		12,855.0
Accumulated Depreciation and Amortization	2,945.7		2,883.9
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	10,266.3		9,971.1
OTHER NONCURRENT ASSETS
Regulatory Assets	364.1		379.1
Operating Lease Assets	55.6		60.4
Deferred Charges and Other Noncurrent Assets	408.9		661.0
TOTAL OTHER NONCURRENT ASSETS	828.6		1,100.5
TOTAL ASSETS	$	11,636.9	$	11,698.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

86

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2025 and December 31, 2024

(Unaudited)

	June 30,		December 31,
	2025		2024
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	203.0	$	—
Accounts Payable:
General	340.2		343.6
Affiliated Companies	169.4		204.9
Risk Management Liabilities	5.9		7.3
Customer Deposits	92.8		108.1
Accrued Taxes	529.8		836.1
Obligations Under Operating Leases	12.0		12.3
Other Current Liabilities	166.5		182.2
TOTAL CURRENT LIABILITIES	1,519.6		1,694.5
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,717.1		3,715.7
Long-term Risk Management Liabilities	41.8		40.2
Deferred Income Taxes	1,225.1		1,201.1
Regulatory Liabilities and Deferred Investment Tax Credits	917.9		987.7
Obligations Under Operating Leases	43.9		48.4
Deferred Credits and Other Noncurrent Liabilities	190.8		127.0
TOTAL NONCURRENT LIABILITIES	6,136.6		6,120.1
TOTAL LIABILITIES	7,656.2		7,814.6
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock –No Par Value:
Authorized – 40,000,000 Shares
Outstanding – 27,952,473 Shares	321.2		321.2
Paid-in Capital	1,021.8		1,020.0
Retained Earnings	2,637.7		2,542.9
TOTAL COMMON SHAREHOLDER’S EQUITY	3,980.7		3,884.1
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	11,636.9	$	11,698.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

87

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2025 and 2024

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2025		2024
OPERATING ACTIVITIES
Net Income	$	165.8	$	89.0
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	188.7		207.8
Deferred Income Taxes	13.7		(10.2)
Asset Impairments and Other Related Charges	—		52.9
Allowance for Equity Funds Used During Construction	(14.1)		(9.8)
Mark-to-Market of Risk Management Contracts	0.2		(7.5)
Property Taxes	205.8		190.8
Change in Other Noncurrent Assets	41.3		4.8
Change in Other Noncurrent Liabilities	(9.0)		18.4
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	2.4		(80.4)
Materials and Supplies	(19.0)		9.7
Accounts Payable	(4.9)		(47.2)
Customer Deposits	(15.3)		39.0
Accrued Taxes, Net	(305.7)		(207.1)
Other Current Assets	7.2		(4.9)
Other Current Liabilities	(23.3)		11.1
Net Cash Flows from Operating Activities	233.8		256.4
INVESTING ACTIVITIES
Construction Expenditures	(504.3)		(455.8)
Change in Advances to Affiliates, Net	114.9		(49.9)
Other Investing Activities	26.8		15.3
Net Cash Flows Used for Investing Activities	(362.6)		(490.4)
FINANCING ACTIVITIES
Capital Contribution from Parent	1.8		—
Issuance of Long-term Debt – Nonaffiliated	—		346.3
Change in Advances from Affiliates, Net	203.0		(110.5)
Principal Payments for Finance Lease Obligations	(2.3)		(2.7)
Dividends Paid on Common Stock	(71.0)		—
Other Financing Activities	1.0		0.8
Net Cash Flows from Financing Activities	132.5		233.9
Net Increase (Decrease) in Cash and Cash Equivalents	3.7		(0.1)
Cash and Cash Equivalents at Beginning of Period	4.5		6.4
Cash and Cash Equivalents at End of Period	$	8.2	$	6.3