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[10-Q] AMERICAN ELECTRIC POWER CO INC Quarterly Earnings Report

Filing Impact
(Moderate)
Filing Sentiment
(Neutral)
Form Type
10-Q
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 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
333-221643AEP TEXAS INC.Delaware51-0007707
333-217143 AEP TRANSMISSION COMPANY, LLCDelaware 46-1125168
1-3457 APPALACHIAN POWER COMPANYVirginia 54-0124790
1-3570 INDIANA MICHIGAN POWER COMPANYIndiana 35-0410455
1-6543 OHIO POWER COMPANYOhio 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA Oklahoma 73-0410895
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANYDelaware 72-0323455
  1 Riverside Plaza,Columbus,Ohio43215-2373  
  Telephone(614)716-1000  

Securities registered pursuant to Section 12(b) of the Act:
Registrant Title of each class Trading SymbolName of Each Exchange on Which Registered
American Electric Power Company Inc. Common Stock, $6.50 par value AEPThe 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.
YesxNo☐
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).
YesxNo☐
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 xAccelerated 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 filerx
      
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☐Nox
AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.


Number of shares
of common stock
outstanding of the
Registrants as of
October 29, 2025
 
American Electric Power Company, Inc.535,265,602 
 ($6.50 par value)
AEP Texas Inc.100 
($0.01 par value)
AEP Transmission Company, LLC (a)NA
Appalachian Power Company13,499,500 
 (no par value)
Indiana Michigan Power Company1,400,000 
 (no par value)
Ohio Power Company27,952,473 
 (no par value)
Public Service Company of Oklahoma9,013,000 
 ($15 par value)
Southwestern Electric Power Company3,680 
 ($18 par value)

(a)100% interest is held by AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of American Electric Power Company, Inc.
NA    Not applicable.


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
September 30, 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
44
   
AEP Texas Inc. and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
50
Condensed Consolidated Financial Statements
53
AEP Transmission Company, LLC and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
59
 Condensed Consolidated Financial Statements
61
Appalachian Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
66
 Condensed Consolidated Financial Statements
69
   
Indiana Michigan Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
75
 Condensed Consolidated Financial Statements
78
   
Ohio Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
84
 Condensed Consolidated Financial Statements
87
   
Public Service Company of Oklahoma: 
 Management’s Narrative Discussion and Analysis of Results of Operations
92
 Condensed Financial Statements
95
   
Southwestern Electric Power Company Consolidated: 
 Management’s Narrative Discussion and Analysis of Results of Operations
101
 Condensed Consolidated Financial Statements
104
   
Index of Condensed Notes to Condensed Financial Statements of Registrants
110
   
Controls and Procedures
198


Part II.  OTHER INFORMATION 
     
 Item 1.  Legal Proceedings
199
 Item 1A.  Risk Factors
199
 Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
199
Item 3.  Defaults Upon Senior Securities
199
 Item 4.  Mine Safety Disclosures
200
 Item 5.  Other Information
200
 Item 6.  Exhibits
201
     
SIGNATURE  
202
     
     
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. 
TermMeaning
   
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 CompaniesAPCo, 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.
AFUDCAllowance for Equity Funds Used During Construction.
AIArtificial Intelligence.
ALJ
Administrative Law Judge.
AOCI Accumulated Other Comprehensive Income.
APCo 
Appalachian Power Company, an AEP electric utility subsidiary. APCo engages in the generation, transmission and distribution of electric power to retail customers in the southwestern portion of Virginia and southern West Virginia.
Appalachian Consumer Rate Relief Funding
Appalachian Consumer Rate Relief Funding, LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
APSCArkansas Public Service Commission.
AROAsset Retirement Obligations.
ASUAccounting Standards Update.
ATMAt-the-Market.
CAAClean Air Act.
CAMTCorporate Alternative Minimum Tax.
CCN
Certificate of Convenience and Necessity.
CCRCoal Combustion Residual.
CEOChief Executive Officer.
CO2
 Carbon dioxide and other greenhouse gases.
CODMChief Operating Decision Maker.
Cook Plant Donald C. Cook Nuclear Plant, a two-unit, 2,296 MW nuclear plant owned by I&M.
i

TermMeaning
   
Cost Recovery Funding
KPCo Cost Recovery Funding, LLC, a wholly-owned subsidiary of KPCo and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to plant retirement costs, deferred storm costs, deferred purchased power expenses, under-recovered purchased power rider costs and issuance-related expenses.
CPCN
Certificate of Public Convenience and Necessity.
CSAPRCross-State Air Pollution Rule.
CWIP Construction Work in Progress.
DCC Fuel
DCC Fuel XVI, DCC Fuel XVII, DCC Fuel XVIII, DCC Fuel XIX, DCC Fuel XX 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.
ELGEffluent Limitation Guidelines.
ENECExpanded Net Energy Cost.
ERCOT Electric Reliability Council of Texas regional transmission organization.
ESAElectric 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 ADITExcess accumulated deferred income taxes.
FACFuel Adjustment Clause.
FASB Financial Accounting Standards Board.
Federal EPAUnited States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FGD Flue Gas Desulfurization or Scrubbers.
FIPFederal 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.
GHGGreenhouse gas.
Gigawatt AI
Gigawatt AI Inc., an equity interest joint venture formed to build the AI-centric operating system for utilities.
G&M
Generation & Marketing.
I&M 
Indiana Michigan Power Company, an AEP electric utility subsidiary. I&M engages in the generation, transmission and distribution of electric power to retail customers in northern and eastern Indiana and southwestern Michigan.
IMTCo
AEP Indiana Michigan Transmission Company, Inc.
IRPIntegrated Resource Plan.
IRS Internal Revenue Service.
ITCInvestment Tax Credit.
ii

TermMeaning
   
IURCIndiana 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.
KPSCKentucky Public Service Commission.
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.
OATTOpen Access Transmission Tariff.
OCC Corporation Commission of the State of Oklahoma.
ODEQOklahoma 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.
PATH-WV
PATH West Virginia Transmission Company, LLC, a joint venture-owned 50% by FirstEnergy and 50% by AEP.
PBA
Performance Based Accreditation.
PFD
Proposal for Decision.
PJM Pennsylvania – New Jersey – Maryland regional transmission organization.
PLRPrivate Letter Ruling.
PM Particulate Matter.
PPAPower Purchase Agreement.
iii

TermMeaning
   
PSA
Purchase and Sale Agreement.
PSO 
Public Service Company of Oklahoma, an AEP electric utility subsidiary. PSO engages in the generation, transmission and distribution of electric power to retail customers in eastern and southwestern Oklahoma.
PTC
Production Tax Credit.
PUCO Public Utilities Commission of Ohio.
PUCT Public Utility Commission of Texas.
Registrant Subsidiaries 
AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants
SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Restoration Funding
AEP Texas Restoration Funding, LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey.
Risk Management Contracts 
Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
A generation plant, jointly owned by AEGCo and I&M, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.
ROEReturn on Equity.
RPMReliability 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.
SECU.S. Securities and Exchange Commission.
SIPState 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.
iv

TermMeaning
   
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.
UTM
Unified Tracking Mechanism.
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.
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 or instability in the banking industry; particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
•The availability and cost of funds to finance working capital and capital needs, particularly (a) if expected sources of capital such as proceeds from the sale of tax credits and anticipated securitizations do not materialize or do not materialize at the level anticipated, and (b) during periods when the time lag between incurring costs and recovery is long and the costs are material.
•Changing demand for electricity, including large load contractual commitments 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, hurricanes, wildfires and drought conditions that pose significant risks including potential litigation and the inability to recover significant damages and restoration costs incurred.
•Limitations or restrictions on the amounts and types of insurance available to cover losses that might arise in connection with natural disasters, wildfires or operations.
•The cost of fuel and its transportation, the creditworthiness and performance of parties who supply and transport fuel and the cost of storing and disposing of used fuel, including coal ash and SNF.
•The availability of fuel and necessary generation capacity and the performance of generation plants.
•The ability to recover fuel and other energy costs through regulated or competitive electric rates.
•The ability to build or acquire generation (including from renewable sources), 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.
•Construction and development risks associated with the completion of the 2026-2030 capital investment plan, including shortages or delays in labor, materials, equipment or parts.
•Prolonged or recurring U.S. federal government shutdowns could adversely affect our operations, regulatory approvals, and financial performance and could cause volatility in the capital markets which may interrupt our access to capital.
•New legislation, litigation or government regulation, including changes to tax laws and regulations, oversight of nuclear generation, 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.
vi

•The risks before, during and after generation of electricity associated with the fuels used or the by-products and wastes of such fuels, including coal ash and SNF.
•Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
•Resolution of litigation or regulatory proceedings or investigations.
•The ability to efficiently manage and recover operation, maintenance and development project costs.
•Prices and demand for power generated and sold 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

Third Quarter of 2025 Compared to Third Quarter of 2024

Earnings Attributable to AEP Common Shareholders increased from $960 million in 2024 to $972 million in 2025 primarily due to:
•Investment in transmission assets, which resulted in higher revenues and income.
•Favorable rate proceedings in AEP’s various jurisdictions.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

Earnings Attributable to AEP Common Shareholders increased from $2.3 billion in 2024 to $3.0 billion in 2025 primarily due to:

•Investment in transmission assets, which resulted in higher revenues and income.
•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 September 30, 2025
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Reported GAAP Earnings$972.0 $166.7 $178.9 $81.1 $149.7 $100.9 $129.8 $189.2 
Adjustments to Reported GAAP Earnings (a):
Mark-to-Market Impact of Commodity Hedging Activities (b)
(0.6)— — — (4.7)— — — 
Impact of Ohio Legislation (c)(8.5)— — — — (8.5)— — 
Total Specified Items (9.1)— — — (4.7)(8.5)— — 
Operating Earnings$962.9 $166.7 $178.9 $81.1 $145.0 $92.4 $129.8 $189.2 

Three Months Ended September 30, 2024
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Reported GAAP Earnings $959.6 $132.5 $191.3 $109.8 $179.1 $112.7 $113.7 $139.1 
Adjustments to Reported GAAP Earnings (a):
Mark-to-Market Impact of Commodity Hedging Activities (b)
6.8 — — — 0.9 — — — 
SEC Matter Loss Contingency (d)19.0 — — — — — — — 
Total Specified Items25.8 — — — 0.9 — — — 
Operating Earnings $985.4 $132.5 $191.3 $109.8 $180.0 $112.7 $113.7 $139.1 

(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 a true-up of the reduction in regulatory assets for OVEC-related purchased power costs through August 2025 as a result of approved legislation in Ohio.
(d)Represents an estimated loss contingency related to a previously disclosed SEC investigation.
2

Nine Months Ended September 30, 2025
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Reported GAAP Earnings$2,998.0 $389.4 $946.2 $352.6 $331.3 $266.7 $221.0 $353.3 
Adjustments to Reported GAAP Earnings (a):
Mark-to-Market Impact of Commodity Hedging Activities (b)
5.4 — — — 11.5 — — — 
Sale of AEP OnSite Partners (c)
9.4 — — — — — — — 
Impact of Ohio Legislation (d)19.2 — — — — 19.2 — — 
FERC NOLC Order (e)(480.1)— (353.9)(28.9)(35.6)0.2 (4.0)(54.1)
Total Specified Items (446.1)— (353.9)(28.9)(24.1)19.4 (4.0)(54.1)
Operating Earnings$2,551.9 $389.4 $592.3 $323.7 $307.2 $286.1 $217.0 $299.2 

Nine Months Ended September 30, 2024
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Reported GAAP Earnings$2,303.0 $340.6 $548.2 $304.6 $359.3 $201.7 $222.0 $277.1 
Adjustments to Reported GAAP Earnings (a):
Mark-to-Market Impact of Commodity Hedging Activities (b)
(52.2)— — — 17.9 — — — 
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 CCR Rule (l)110.7 — — — 10.6 41.3 — — 
SEC Matter Loss Contingency (m)19.0 — — — — — — — 
Total Specified Items14.8 15.6 8.2 20.3 (41.8)52.9 (48.8)(16.1)
Operating Earnings$2,317.8 $356.2 $556.4 $324.9 $317.5 $254.6 $173.2 $261.0 

(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 an adjustment to the estimated loss on the sale of AEP OnSite Partners as a result of the contractual working capital true-up.
(d)Represents the reduction in regulatory assets for OVEC-related purchased power costs as a result of approved legislation in Ohio in April 2025.
(e)Represents the impact of the FERC NOLC Order for years 2021-2024.
(f)Represents the impact of the remeasurement of Excess ADIT in Arkansas and Michigan as a result of the denial of SWEPCo’s request regarding the Turk Plant by the APSC and the approved treatment of stand-alone NOLCs by the MPSC.
(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 sale of AEP OnSite Partners.
(k)Represents employee severance charges.
(l)Represents the impact of the Federal EPA Revised CCR Rule.
(m)Represents an estimated loss contingency related to a previously disclosed SEC investigation.





3

RECENT DEVELOPMENTS AND TRANSACTIONS

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, compared to prior year, are shown in the table below. The increase in commercial sales volumes was primarily due to new data processor loads. Industrial sales growth remains relatively slow due to the continuing impact of elevated interest rates and tariff-related uncertainty. The weather-normalized residential sales have moderated, but the pace of growth continues to be impacted by energy efficiency and continuing inflationary pressures.

13743895422008
(a)Percentage change for the three months ended September 30, 2025 as compared to the three months ended September 30, 2024.
(b)Percentage change for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024.

In July 2025, AEP updated its 2025 forecasted retail sales volumes. The table below summarizes those updated 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.

4

13743895422549
(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 six months of actual results plus six months of forecasted values based on underlying economic and demographic trends.

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.
CompanyJurisdictionLarge Load TariffStatusCustomer Eligibility
APCoVirginiaLarge Power ServicePendingNew load of 150 MWs or more/100 MWs for individual site
APCoWest VirginiaLarge Capacity/Industrial PowerApprovedNew load of 150 MWs or more/100 MWs for individual site
I&MIndianaIndustrial PowerApprovedNew load of 150 MWs or more/70 MWs for individual site
I&MMichiganLarge Load PendingNew load of 50 MWs or more
KPCoKentuckyIndustrial General ServiceApprovedNew commercial or industrial load of 150 MWs or more
OPCoOhioData CenterApprovedNew data center load of 25 MWs or more
SWEPCoTexasElectric Service Large LoadPendingNew load of 75 MWs 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 establishes criteria for new large load interconnections and directs the PUCT to ensure that these large load customers pay a reasonable share of allocated transmission costs.


5

PSO New Generation Resources

In 2025, PSO expanded its generation portfolio by acquiring four power generation facilities, as listed below, for a total of $1.7 billion. See “Green Country Power Plant, Pixley Solar Energy Facility, Flat Ridge IV Wind Energy Facility and Flat Ridge V Wind Energy Facility” section of Note 6 for additional information.

Plant NameFuel TypeLocationAcquisition DateGenerating Capacity
(in MWs)
Green CountryNatural GasJenks, OKJune 2025795 
PixleySolarBarber County, KSMay 2025189 
Flat Ridge IVWindKingman and Harper Counties, KSJune 2025135 
Flat Ridge VWindKingman and Harper Counties, KSAugust 2025153 
Total1,272 

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 1,826 MWs of owned renewable generation facilities, totaling approximately $4.5 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 1,059 MWs of renewable PPAs. The recently enacted OBBBA legislation is not expected to affect the eligibility of these generation facilities for federal tax incentives. The following table summarizes regulatory approvals received for active renewable projects as of September 30, 2025:

CompanyGeneration TypeExpected Commercial OperationOwned/PPAGenerating Capacity
(in MWs)
APCoSolar2026-2027PPA105 
APCo (a)Wind2025-2026Owned344 
I&MSolar2026-2027PPA280 
I&MWind2026-2030PPA674 
I&MSolar2028Owned469 
PSO (b)Wind2026Owned265 
PSO (b)Solar2027Owned150 
SWEPCoWind2025Owned598 
Total Approved Renewable Projects2,885 

(a)APCo has 344 MWs of wind capacity under construction.
(b)One wind project is under construction and one solar project has not yet achieved all conditions necessary to issue a notice to proceed.


6

Natural Gas Generation

In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT for construction of the Hallsville Natural Gas Plant (450 MWs) and the fuel conversion of Welsh Plant, Units 1 and 3 to natural gas. In the application for the CCN, SWEPCo seeks to site the Hallsville Natural Gas Plant at the location of the now-retired Pirkey 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 filed an application with the IURC to acquire the Oregon Generation Plant (Oregon), an 870 MW combined-cycle power generation facility located near Toledo, Ohio. In April 2025, I&M submitted a FERC 203 application for the acquisition. If approved, the project will help I&M address increasing capacity and power needs. In August 2025, I&M reached a unanimous settlement in the filing submitted to the IURC with intervening parties approving the acquisition of the Oregon facility and cost recovery. The IURC will issue an order on I&M’s settlement filing in the fourth quarter of 2025. I&M expects to close on the transaction in the first quarter of 2026.

In September 2025, PSO filed an application with the OCC seeking regulatory approval of a new 450 MW combustion turbine configuration at its existing Northeastern facility in Oklahoma as part of a project portfolio. If approved, the combustion turbines would be projected to be online by the end of 2029.

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.

CompanyIssuance DateProjected
In-Service Dates		Generating Capacity
(in MWs)
PSO (a)November 20232027/20281,500 
I&M (b)September 202420294,000 
APCo (c)May 202420281,100 
APCo (d)May 20252029800 
APCo (e)May 20252029300 
Total Significant RFPs7,700 

(a)RFP is seeking 1,500 MWs of SPP accredited capacity and associated energy through an all-source solicitation that was negotiated and filed for regulatory approval in September 2025.
(b)RFP is seeking up to 4,000 MWs (cumulatively) from intermittent (wind, solar), non-intermittent (dispatchable) and emerging technology resources. Five wind resources selected from the 2024 RFP have already been submitted and approved by the IURC totaling 574 MWs. I&M expects to file applications with the IURC for regulatory approval of additional resources from the 2024 RFP.
(c)RFP is seeking wind, solar, stand-alone battery energy storage systems and Renewable Energy Certificates.
(d)RFP is seeking 800 MWs of wind, solar, and/or co-located or stand-alone battery energy storage systems PSAs (owned).
(e)RFP is seeking 300 MWs of wind, solar, hydro, or geothermal PPAs.


7

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 September 30, 2025, by year, for the five-year period 2025-2029:

I&MPSO SWEPCo
Natural GasWindNatural GasWindNatural GasWind
Delivery Start Year(in MWs)
2025— — 760 27 150 91 
2026615 73 460 86 150 100 
2027779 — 410 86 300 100 
20281,003 — 410 — 450 — 
20291,003 — 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 tables summarize the completed and pending base rate case proceedings. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

Annual
Base RevenueApprovedNew Rates
CompanyJurisdictionIncreaseROEEffective
(in millions)
APCo/WPCoWest Virginia$76.1 9.25%August 2025 (a)

(a)The WVPSC approved recovery of the base rate increase through current ENEC rates. The WVPSC issued an interim order approving securitization of APCo and WPCo under-recovery balances, with activity subsequent to 2024 subject to a final prudence review prior to securitization. See the “2024 West Virginia Base Rate Case” and “2025 West Virginia Securitization Filing” sections of Note 4 for additional information.

Pending Base Rate Case Proceedings

Annual
FilingBase RevenueRequested
CompanyJurisdictionDateIncrease RequestROE
(in millions)
SWEPCoArkansasMarch 2025$114.0 10.9%
OPCoOhioMay 202597.4 10.9%
KPCoKentuckyAugust 202595.6 10.0%
SWEPCoTexasOctober 202594.9 10.75%


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Other Significant Regulatory Matters

2025 West Virginia Securitization Filing

In March 2025, APCo and WPCo (the Companies) requested to finance, through the issuance of securitization bonds, approximately $2.4 billion of West Virginia jurisdictional undepreciated property balances and regulatory assets. In the third quarter of 2025, the Companies submitted post-hearing exhibits with a revised securitization request of approximately $2.5 billion, including: (a) $412 million of the Companies’ combined unrecovered ENEC balances, (b) $1.7 billion of undepreciated West Virginia jurisdictional plant balances as of December 31, 2022 for the Amos, Mitchell and Mountaineer Plants, (c) $237 million of environmental costs previously approved for recovery through a separate West Virginia surcharge and (d) $158 million of West Virginia jurisdictional deferred major storm operation and maintenance costs. See “2025 West Virginia Securitization Filing” section of Note 4 for additional information.

In August 2025, the WVPSC issued an interim order stating that it will approve the Companies’ future securitization of the generation plant assets, ENEC under-recovery balances, environmental costs and deferred storm operation and maintenance costs. All amounts above are subject to further review in a future final securitization financing order that the Companies expect will be issued by the WVPSC in the fourth quarter of 2025. Upon receipt of the final financing order, the Companies expect to proceed with the securitization bonds issuance process and to complete the securitization in the first half of 2026, subject to market conditions.

2025 Virginia Securitization Legislation and Securitization Filing

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

In July 2025, APCo filed a request with the Virginia SCC to finance, through the issuance of proposed 20-year securitization bonds, approximately $1.4 billion of Virginia jurisdictional undepreciated property balances and a major storm operation and maintenance regulatory asset deferral balance. This proposed securitization included: (a) $1.2 billion of undepreciated Virginia jurisdictional plant balances as of December 31, 2023 for the Amos and Mountaineer Plants and (b) $141 million of Virginia jurisdictional major storm other operation and maintenance expenses deferred during the 2024-2025 biennial period. In September 2025, Virginia SCC staff submitted testimony concluding that all costs proposed by APCo for securitization are eligible for securitization in accordance with Virginia law. While also concluding that APCo’s proposed securitization of the Amos and Mountaineer Plants over 20 years offers benefits to customers through rate relief, Virginia SCC staff took no position on APCo’s proposed securitization of major storm other operation and maintenance expenses due to the lack of significant benefit or cost savings for customers. In October 2025, the Hearing Examiner recommended the Virginia SCC approve the requested $1.4 billion for securitization. The Virginia SCC’s final order is due in November 2025.


9

NOLCs in Transmission Formula Rates - June 2025 FERC Order

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

CompanyIncrease (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&M16.8 27.8 — 44.6 
PSO(12.4)15.6 — 3.2 
SWEPCo16.8 38.9 — 55.7 
AEPTCo214.3 203.2 (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:

CompanyIncrease in Pretax Income from the Recognition of Regulatory AssetsReduction in Income Tax Expense (a)Increase in Net Income
(in millions)
I&M$20.2 $49.5 $69.7 
PSO12.1 44.7 56.8 
SWEPCo35.4 101.1 136.5 
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.


10

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)JurisdictionStatus
APCoVirginiaApproved
APCo/WPCoWest Virginia(b)Pending
I&MIndianaApproved
I&MMichiganApproved
KGPCoTennesseeApproved
KPCoKentucky(b)Pending
PSOOklahoma(b)Approved, subject to refund
SWEPCoArkansas(c)Pending
SWEPCoLouisiana(b)Pending
SWEPCoTexasApproved, subject to refund

(a)AEP Texas and OPCo do not have NOLCs on a stand-alone basis.
(b)Awaiting receipt of jurisdiction specific IRS PLR.
(c)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 September 30, 2025, AEP has NOLC regulatory assets of $118 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 are being used to help finance AEP’s capital plan. See “Noncontrolling Interest in OHTCo and IMTCo” section of Note 6 for additional information.

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 securitized plant retirement costs as ordered by the KPSC.

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.
11

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.

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, through the third quarter of 2025, OPCo recorded a $24 million reduction to its OVEC-related purchased power regulatory asset for deferred net costs that are no longer probable of future recovery. Management is unable to predict the future impact to net income, cash flows and financial condition arising from the future changes in OPCo’s rate setting mechanisms and the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and the market revenues OPCo receives from that purchased power.

Texas Legislation

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

The UTM permits a qualifying electric utility to defer all or a portion of costs associated with its eligible transmission and distribution capital investments, including depreciation expense and carrying costs, as a regulatory asset. The tracking mechanism is available through 2035 and is an alternative to the existing capital tracking mechanisms in Texas. As a result of the new legislation, AEP Texas deferred approximately $39 million of eligible costs through September 2025 as a regulatory asset.

In October 2025, AEP Texas submitted its first filing with the PUCT seeking recovery of eligible costs through the UTM established by HB 5247. This filing combined three recovery mechanisms (Interim Transmission Cost of Service and Distribution Cost Recovery Factor capital trackers and the Transmission Cost Recovery Factor) into a single filing. The capital tracker incremental revenue requirement sought in this filing is $109 million, including a request to recover, over a 12-month period, $42 million of eligible costs related to UTM deferrals and $2 million of eligible costs related to the System Resiliency Plan deferrals, both inclusive of equity carrying charges through the July 2025 test year period end. Investments included in the UTM and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate review before the PUCT. If any of these deferred costs are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

Oklahoma Legislation

Effective August 28, 2025, in accordance with Oklahoma Senate Bill 998 (SB 998), a public utility 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 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. Management does not expect the legislation to have a material impact on 2025 net income, cash flows and financial condition.
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Federal Tax Legislation

On July 4, 2025, President Trump signed H.R. 1 into law, commonly known as the One Big Beautiful Bill Act (OBBBA). This budget reconciliation legislation modifies and accelerates the phase out of technology neutral PTCs and ITCs available for wind and solar projects, adds new restrictions to guard against certain foreign ownership or influence with respect to otherwise credit-eligible projects and makes 100% bonus depreciation permanent for certain non-regulated entities. With the exception of bonus depreciation, this legislation is prospective and has no material impact on the current period financial statements.

On August 15, 2025, the Department of Treasury and the IRS issued new and revised wind and solar tax credit guidance, Notice 2025-42, which modified the definition of “begin construction” for tax purposes by eliminating the previously available 5% cost safe harbor standard for projects that begin construction after September 1, 2025. This guidance is not expected to have a material impact on the Registrants.

On September 30, 2025, the Department of Treasury and the IRS issued interim guidance regarding the application of CAMT. The Registrants are subject to CAMT and will continue to evaluate the impact of that interim guidance.

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

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 September 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.


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Fuel Cell Agreement

In November 2024, AEP executed a purchase agreement to acquire 100 MWs of solid oxide fuel cells with an option to acquire up to one gigawatt in total by the end of 2025. AEP, through its subsidiaries, 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. By the first quarter of 2025, OPCo had 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.

In September 2025, an intervenor filed a request for rehearing with the Supreme Court of Ohio, opposing the PUCO's approval and claiming that the order was unlawful, anti-competitive, and discriminatory.

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

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies for additional information.

Claims for Indemnification Made by Owners of the Gavin Power Station

AEP sold the Gavin Power Station to Gavin Power LLC and Lighthouse Generation LLC in 2017. Pursuant to the PSA for that transaction, AEP maintained responsibility to complete closure of the 300 acre unlined fly ash reservoir (FAR) pond in accordance with the closure plan approved by the Ohio EPA and to indemnify the purchasers for that work. In November 2022, the Federal EPA made several assertions related to the CCR Rule (see “CCR Rule” section below for additional information), including an assertion that the closure of the FAR is noncompliant with the CCR Rule in multiple respects. The owners of the Gavin Power Station have notified AEP that they believe they are entitled to indemnification for any damages that may result from these claims. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. See “Claims for Indemnifications Made by Owners of the Gavin Power Station” section of Note 5 for additional information.

ENVIRONMENTAL ISSUES

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

Impact of Environmental Compliance on the Generating Fleet

The rules and environmental control requirements discussed below will have a material impact on AEP’s operations.  As of September 30, 2025, AEP owned generating capacity of approximately 24,500 MWs, of which approximately 10,700 MWs were coal-fired.   In April 2024, the Federal EPA announced four major new rules directed at fossil-fuel electric generation facilities. Management continues to evaluate the impacts of these rules on the plans for the future of AEP’s generating fleet, in particular, the economic feasibility of making the requisite environmental investments in AEP’s fossil generation fleet. AEP continues to refine the cost estimates of complying with these rules to identify the best alternative for promoting compliance with all of the rules while meeting AEP’s obligations to provide reliable and affordable electricity.

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


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Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states 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. In September 2025, the Federal EPA issued an advanced notice of proposed rulemaking, soliciting information to assist the Federal EPA in potentially restructuring the Regional Haze Rule (RHR). Under the current RHR, states must submit SIPs to protect visibility in mandatory Class I Federal areas to demonstrate reasonable progress towards the national visibility goal. The Federal EPA intends to propose revisions to the RHR based on the input received.

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


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Cross-State Air Pollution Rule

CSAPR is a regional trading program that the Federal EPA began implementing in 2015 to address interstate transport of emissions that contribute significantly to nonattainment and interfere with maintenance of the 1997 ozone NAAQS and the 1997 and 2006 PM2.5 NAAQS in downwind states.  CSAPR relies on SO2 and NOX allowances and individual state budgets to compel further emission reductions from electric utility generating units.  Interstate trading of allowances is allowed on a restricted basis. The Federal EPA has revised, or updated, the CSAPR trading programs several times since they were established.

In 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 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
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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. Management is 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.

AEP is committed to delivering reliable, affordable power and routinely submits IRPs in various regulatory jurisdictions to address future generation needs. A recent evaluation demonstrated that changing external conditions and business growth, including unprecedented load growth, evolving market and policy dynamics, and jurisdictional preferences will impact AEP’s corporate-wide pathway to reduce Scope 1 GHG emissions by 80% by 2030 through collective state IRPs. Accordingly, AEP continues to focus on supporting state-based clean energy mandates and decarbonization targets, including meeting the Virginia Clean Economy Act and Michigan Public Act 235 mandates that are on track for achievement. AEP remains committed to seeking advanced low-carbon generation solutions where supported. As an example, I&M and APCo are seeking early site permits to bring small modular reactors to Virginia and Indiana. In light of this shift, AEP will continue to assess aspirations to achieve net-zero Scope 1 and 2 emissions by 2045. AEP’s performance will ultimately be driven by the needs and desires of the states AEP serves and the company will continue to engage with regulators and policymakers to meet the energy needs while facilitating the delivery of reliable, affordable energy.

MATS Rule

In April 2024, the Federal EPA issued a revised MATS rule for power plants. 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.

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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 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.

In September 2025, the Federal EPA proposed to extend the compliance deadlines in the 2024 ELG Rule by five years as well as to establish a site-specific mechanism for extending compliance deadlines for both the 2020 and 2024 ELG Rules. The Federal EPA also published a direct final rule extending to December 31, 2031, the 2024 ELG Rule deadline for submitting a NOPP electing to cease coal combustion by December 31, 2034. The direct final rule extending the NOPP deadline becomes effective on December 1, 2025, if no adverse comments are received; otherwise, the proposed NOPP extension must complete the notice and comment process initiated by the proposed rule before taking effect. The Federal EPA is also soliciting comments on zero liquid discharge technology to be used in a future rulemaking. Management cannot predict the outcome of 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 September 30, 2025, of generating facilities retired or planned for retirement in advance of the retirement date currently authorized for ratemaking purposes:
CompanyPlantNet
Investment (a)		Accelerated Depreciation Regulatory AssetActual/Projected
Retirement
Date		Current Authorized
Recovery
Period		Annual Depreciation (b)
(in millions)(in millions)
PSONortheastern Plant, Unit 3$73.9 $212.8 2026(c)$16.1 
SWEPCoPirkey Plant— 134.1 (d)2023(e)— 
SWEPCoWelsh Plant, Units 1 and 3278.8 206.2 2028(f)(g)46.5 

(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, Texas and FERC 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. SWEPCo requested recovery of the Texas jurisdictional share of the remaining net book value of the Pirkey Plant in its 2025 Texas Base Rate Case. See the “Regulated Generating Units” section of Note 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 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 nine months ended September 30, 2025 as compared to the three months ended and nine months ended September 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 nine months ended September 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 EndedNine Months Ended
September 30,September 30,
 2025202420252024
 (in millions)
Vertically Integrated Utilities$578.2 $571.5 $1,335.0 $1,198.0 
Transmission and Distribution Utilities267.6 245.2 656.1 542.3 
AEP Transmission Holdco199.9 214.7 1,012.9 624.1 
Generation & Marketing44.3 93.3 208.8 226.1 
Corporate and Other(118.0)(165.1)(214.8)(287.5)
Earnings Attributable to AEP Common Shareholders$972.0 $959.6 $2,998.0 $2,303.0 

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 
September 30,		Nine Months Ended 
September 30,
2025202420252024
 (in millions of KWhs)
Retail:    
Residential8,842 8,959 24,618 24,191 
Commercial7,355 6,910 19,548 18,763 
Industrial8,552 8,562 25,248 25,563 
Miscellaneous599 612 1,701 1,718 
Total Retail25,348 25,043 71,115 70,235 
Wholesale (a)4,217 3,559 12,451 10,498 
Total KWhs29,565 28,602 83,566 80,733 

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


Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2025202420252024
 (in degree days)
Eastern Region    
Actual – Heating
1 — 1,736 1,302 
Normal – Heating
2 3 1,702 1,746 
Actual – Cooling
722 854 1,104 1,328 
Normal – Cooling
733 746 1,085 1,089 
Western Region    
Actual – Heating
— — 966 743 
Normal – Heating
— 1 903 910 
Actual – Cooling
1,447 1,510 2,278 2,486 
Normal – Cooling
1,415 1,434 2,186 2,173 
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Vertically Integrated Utilities
Reconciliation of 2024 to 2025 Earnings Attributable to AEP Common Shareholders
(in millions)
 
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2024 Earnings Attributable to AEP Common Shareholders$571.5 $1,198.0 
  
Changes in Revenues: 
Retail Revenues212.4 669.1 
Off-system Sales29.9 92.2 
Transmission Revenues23.1 95.0 
Other Revenues17.3 12.5 
Total Change in Revenues282.7 868.8 
  
Changes in Expenses and Other: 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation(68.0)(194.0)
Other Operation and Maintenance(116.6)(143.3)
Asset Impairments and Other Related Charges— 13.4 
Depreciation and Amortization(16.8)(123.5)
Taxes Other Than Income Taxes(3.5)12.6 
Other Income(0.4)(0.4)
Allowance for Equity Funds Used During Construction6.5 14.4 
Non-Service Cost Components of Net Periodic Pension Cost(9.1)(20.9)
Interest Expense(29.2)(83.5)
Total Change in Expenses and Other(237.1)(525.2)
  
Income Tax Benefit(39.0)(207.3)
Equity Earnings of Unconsolidated Subsidiary(0.2)(0.3)
Net Income Attributable to Noncontrolling Interests0.3 1.0 
2025 Earnings Attributable to AEP Common Shareholders$578.2 $1,335.0 

Third Quarter of 2025 Compared to Third Quarter of 2024

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

•Retail Revenues increased $212 million primarily due to the following:
•A $140 million increase in rider revenues.
•A $64 million increase in weather-normalized revenues primarily in the residential and commercial classes, partially offset by a decrease in the industrial class.
•A $42 million increase in base rate revenues at I&M and PSO.
•A $35 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 $39 million decrease due to regulatory provisions for refund at I&M.
•A $22 million decrease in weather-related usage primarily in the residential class driven by an 8% decrease in cooling degree days.
•A $10 million decrease in rider revenues at APCo.
•Off-system Sales increased $30 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales at I&M.
22

•Transmission Revenues increased $23 million primarily due to continued transmission investment.
•Other Revenues increased $17 million primarily due to an increase in sales of renewable energy credits at APCo and PSO and an increase in associated business development revenues driven by costs associated with a third-party construction project at SWEPCo.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $68 million primarily due to increases at APCo, I&M and PSO, partially offset by a decrease at SWEPCo.
•Other Operation and Maintenance expenses increased $117 million primarily due to the following:
•A $34 million increase in distribution expenses primarily due to vegetation management costs.
•An $18 million increase in employee-related expenses.
•A $17 million increase in PJM and SPP transmission expenses.
•A $10 million increase in generation expenses at PSO primarily due to acquisitions of generation facilities in 2025.
•A $9 million increase in transmission vegetation management costs.
•A $7 million increase in nuclear expenses at Cook Plant.
•Depreciation and Amortization expenses increased $17 million primarily due to the amortization of the Storm Recovery Funding securitized assets at SWEPCo and an overall higher depreciable base across all companies.
•Allowance for Equity Funds Used During Construction increased $7 million primarily due to higher CWIP.
•Non-Service Cost Components of Net Periodic Benefit Cost increased $9 million primarily due to an increase in discount rates from 2024 to 2025.
•Interest Expense increased $29 million primarily due to higher long-term debt balances at PSO, an increase primarily associated with Storm Recovery Funding securitization bonds at SWEPCo and an increase at KPCo due to issuing securitization bonds in June 2025.
•Income Tax Benefit decreased $39 million primarily due to the following:
•A $14 million decrease due to an increase in flow-through cost of removal.
•A $10 million decrease due to an increase in pretax book income.
•An $8 million decrease due to the timing of the recognition of PTCs.
•A $7 million decrease due to an increase in flow-through CAMT expense.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

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

•Retail Revenues increased $669 million primarily due to the following:
•A $240 million increase in rider revenues across all companies.
•A $173 million increase in base rate revenues at I&M and PSO.
•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 $95 million increase in fuel revenues primarily due to increases at APCo and I&M, partially offset by a decrease at PSO.
•A $92 million increase in weather-normalized revenues primarily in the residential and commercial classes, partially offset by a decrease in the industrial class.
•An $18 million increase in weather-related usage primarily in the residential class driven by a 32% increase in heating degree days.
These increases were partially offset by:
•A $110 million decrease due to regulatory provisions for refund at I&M.
•Off-system Sales increased $92 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales at I&M.
•Transmission Revenues increased $95 million primarily due to the following:
•A $56 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $39 million increase due to continued transmission investment.
•Other Revenues increased $13 million primarily due to an increase in sales of renewable energy credits at APCo.


23

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $194 million primarily due to increases at APCo and I&M, partially offset by decreases at PSO and SWEPCo.
•Other Operation and Maintenance expenses increased $143 million primarily due to the following:
•A $100 million increase in PJM and SPP transmission expenses.
•A $56 million increase in distribution expenses primarily due to vegetation management costs.
•A $53 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•An $18 million increase at APCo due to recoverable energy assistance program expenses for qualified Virginia customers.
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 due 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 $124 million primarily due to the following:
•A $77 million increase primarily due to a higher depreciable base at APCo, I&M and SWEPCo.
•A $17 million increase at SWEPCo due to the amortization of the Storm Recovery Funding securitized assets.
•A $16 million increase due to a prior year deferral combined with current year amortization of Excess ADIT as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking at I&M.
•Taxes Other Than Income Taxes decreased $13 million primarily due to lower business and occupation taxes at APCo and WPCo.
•Allowance for Equity Funds Used During Construction increased $14 million primarily due to higher CWIP.
•Non-Service Cost Components of Net Periodic Benefit Cost increased $21 million primarily due to an increase in discount rates from 2024 to 2025.
•Interest Expense increased $84 million primarily due to the following:
•A $37 million increase 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 at I&M, PSO and SWEPCo.
•A $26 million increase due to higher long-term debt balances at PSO.
•A $17 million increase associated with Storm Recovery Funding securitization bonds at SWEPCo.
•Income Tax Benefit decreased $207 million primarily due to the following:
•A $212 million decrease due to a reduction in Excess ADIT regulatory liabilities at I&M, PSO and SWEPCo as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking recorded in 2024.
•A $67 million decrease due to an increase in pretax book income.
•A $32 million decrease due to the reversal of a regulatory liability related to the merchant portion of Turk Plant Excess ADIT as a result of the APSC’s denial of SWEPCo’s request to allow the merchant portion of the Turk Plant to serve Arkansas customers recorded in 2024.
•A $21 million decrease due to a decrease in amortization of Excess ADIT.
These decreases were partially offset by:
•A $114 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

24

TRANSMISSION AND DISTRIBUTION UTILITIES

Summary of KWh Energy Sales for Transmission and Distribution Utilities
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2025202420252024
 (in millions of KWhs)
Retail:    
Residential8,256 8,206 21,566 21,079 
Commercial12,610 9,671 33,240 26,871 
Industrial7,009 6,725 20,813 20,363 
Miscellaneous209 213 553 573 
Total Retail (a)28,084 24,815 76,172 68,886 
Wholesale (b)552 504 1,683 1,347 
Total KWhs28,636 25,319 77,855 70,233 

(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.


Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2025202420252024
 (in degree days)
Eastern Region    
Actual – Heating
— — 2,077 1,573 
Normal – Heating
3 4 1,996 2,056 
Actual – Cooling
734 844 1,076 1,266 
Normal – Cooling
707 699 1,032 1,008 
Western Region    
Actual – Heating
— — 296 162 
Normal – Heating
— — 208 198 
Actual – Cooling
1,367 1,457 2,520 2,801 
Normal – Cooling
1,348 1,401 2,369 2,487 
25

Transmission and Distribution Utilities
Reconciliation of 2024 to 2025 Earnings Attributable to AEP Common Shareholders
(in millions)
  
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2024 Earnings Attributable to AEP Common Shareholders$245.2 $542.3 
  
Changes in Revenues: 
Retail Revenues86.8 151.3 
Off-system Sales16.1 41.9 
Transmission Revenues18.2 32.4 
Other Revenues(7.2)(61.1)
Total Change in Revenues113.9 164.5 
  
Changes in Expenses and Other: 
Purchased Electricity for Resale
(46.3)(38.4)
Purchased Electricity from AEP Affiliates(4.3)37.1 
Other Operation and Maintenance(24.4)(102.7)
Asset Impairments and Other Related Charges— 52.9 
Depreciation and Amortization3.0 48.0 
Taxes Other Than Income Taxes(8.8)(4.5)
Other Income(3.3)(5.3)
Allowance for Equity Funds Used During Construction1.3 5.5 
Non-Service Cost Components of Net Periodic Benefit Cost(1.0)(0.4)
Interest Expense— (19.6)
Total Change in Expenses and Other(83.8)(27.4)
  
Income Tax Expense(7.8)(25.6)
Equity Earnings of Unconsolidated Subsidiary0.1 2.3 
  
2025 Earnings Attributable to AEP Common Shareholders$267.6 $656.1 

Third Quarter of 2025 Compared to Third Quarter of 2024

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

•Retail Revenues increased $87 million primarily due to the following:
•A $49 million increase due to higher prices for purchased power for OPCo’s SSO customers.
•A $31 million increase in base case and rider revenues.
•A $12 million increase in weather-normalized revenues primarily in the residential class.
These increases were partially offset by:
•A $9 million decrease in weather-related usage primarily driven by a 13% decrease in cooling degree days in Ohio.
•Off-system Sales increased $16 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.
•Transmission Revenues increased $18 million primarily due to the following:
•A $28 million increase in interim rates driven by increased transmission investments in Texas.
This increase was partially offset by:
•A $14 million decrease due to lower peak loads included in the 2025 billing rates in Texas.


26

•Other Revenues decreased $7 million primarily due to the following:
•A $12 million decrease primarily due to the maturity of Transition Funding III LLC securitization bonds in December 2024.
This decrease was partially offset by:
•A $5 million increase primarily due to data center load study revenues in Ohio.

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

•Purchased Electricity for Resale expenses increased $46 million primarily due to the following:
•A $39 million increase in recoverable auction purchases in Ohio primarily due to higher prices.
•A $6 million increase in recoverable alternative energy rider expenses in Ohio.
•Other Operation and Maintenance expenses increased $24 million primarily due to the following:
•A $15 million increase in recoverable transmission expenses in Texas.
•A $4 million increase in distribution expenses in Texas.
•Depreciation and Amortization expenses decreased $3 million primarily due to the following:
•A $19 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.
•A $6 million decrease due to the deferral of eligible costs related to the UTM.
These decreases were partially offset by:
•An $11 million increase primarily due to higher depreciable base and lower capital rider under recoveries in Ohio.
•A $9 million increase due to a higher depreciable base in Texas.
•Taxes Other Than Income Taxes increased $9 million primarily due to an increase in property taxes in Ohio.
•Income Tax Expense increased $8 million primarily due to an increase in pretax book income.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

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

•Retail Revenues increased $151 million primarily due to the following:
•A $164 million increase in base case and rider revenues.
•A $25 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:
•A $39 million decrease due to lower purchased power in OPCo’s SSO customers.
•Off-system Sales increased $42 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.
•Transmission Revenues increased $32 million primarily due to the following:
•A $70 million increase in interim rates driven by increased transmission investments in Texas.
•An $11 million increase primarily due to continued transmission investment in Ohio.
These increases were partially offset by:
•A $48 million decrease due to lower peak loads included in the 2025 billing rates in Texas.
•Other Revenues decreased $61 million primarily due to the following:
•A $54 million decrease primarily due to the maturity of Transition Funding III LLC securitization bonds in December 2024.
•A $7 million decrease 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 for Resale expenses increased $38 million primarily due to the following:
•A $24 million increase primarily due to the amortization of OVEC-related purchased power regulatory assets driven by higher market prices.
•A $24 million increase due to a reduction in regulatory assets for OVEC-related purchased power costs that are no longer probable of future recovery due to approved legislation in Ohio in 2025.
These increases were partially offset by:
•A $6 million decrease in recoverable alternative energy rider expenses.
•Purchased Electricity from AEP Affiliates expenses decreased $37 million primarily due to decreased recoverable purchases to serve SSO customers in Ohio.

27

•Other Operation and Maintenance expenses increased $103 million primarily due to the following:
•A $120 million increase in recoverable transmission expenses.
•A $16 million increase in transmission and distribution 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 $20 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 decreased $48 million due to the following:
•A $51 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.
•A $17 million decrease due to the deferral of eligible costs related to the UTM.
•A $9 million decrease primarily due to capital rider under-recoveries in Ohio.
These decreases were partially offset by:
•A $28 million increase due to a higher depreciable base in Texas.
•Other Income decreased $5 million primarily due to lower interest income as a result of lower advances to affiliates.
•Allowance for Equity Funds Used During Construction increased $6 million primarily due to a higher AFUDC base.
•Interest Expense increased $20 million primarily due to:
•A $32 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 in the debt component of AFUDC in Texas.
These increases were partially offset by:
•A $19 million decrease due to the deferral of eligible costs related to the UTM.
•Income Tax Expense increased $26 million primarily due to an increase in pretax book income.



28

AEP TRANSMISSION HOLDCO
Summary of Investment in Transmission Assets for AEP Transmission Holdco
September 30,
20252024
(in millions)
Plant in Service$16,876.9 $15,125.0 
Construction Work in Progress2,376.4 2,411.1 
Accumulated Depreciation and Amortization1,891.6 1,555.5 
Total Transmission Property, Net$17,361.7 $15,980.6 

AEP Transmission Holdco
Reconciliation of 2024 to 2025 Earnings Attributable to AEP Common Shareholders
(in millions)
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2024 Earnings Attributable to AEP Common Shareholders$214.7 $624.1 
Changes in Transmission Revenues:
Transmission Revenues60.7 372.2 
Total Change in Transmission Revenues60.7 372.2 
Changes in Expenses and Other:
Other Operation and Maintenance(13.3)(12.9)
Depreciation and Amortization(13.0)(33.3)
Taxes Other Than Income Taxes(6.1)(6.7)
Interest and Investment Income(1.5)(5.9)
Allowance for Equity Funds Used During Construction(3.5)— 
Non-Service Cost Components of Net Periodic Pension Cost(1.2)(1.7)
Interest Expense(7.1)(12.5)
Total Change in Expenses and Other(45.7)(73.0)
Income Tax Expense(1.1)182.6 
Equity Earnings of Unconsolidated Subsidiaries(2.2)(6.1)
Net Income Attributable to Noncontrolling Interests(26.5)(86.9)
2025 Earnings Attributable to AEP Common Shareholders$199.9 $1,012.9 

Third Quarter of 2025 Compared to Third 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 $61 million primarily due to continued transmission investment.

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

•Other Operation and Maintenance expenses increased $13 million primarily due to an increase in employee-related expenses, vegetation management expenses and other miscellaneous expenses.
•Depreciation and Amortization expenses increased $13 million primarily due to a higher depreciable base.
•Taxes other than Income Taxes increased $6 million due to higher property taxes driven by increased investment.
•Interest Expense increased $7 million primarily due to higher long-term debt balances and interest rates.
29

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

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 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 $372 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 $158 million increase due to continued transmission investment.

Expenses and Other, Income Tax Expense, Equity Earnings of Unconsolidated Subsidiaries and Net Income Attributable to Noncontrolling Interests changed between years as follows:
•Other Operation and Maintenance expenses increased $13 million primarily due to an increase in vegetation management expenses, affiliated rent expense and other miscellaneous expenses, partially offset by a 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 $33 million due to a higher depreciable base.
•Taxes other than Income Taxes increased $7 million primarily due to higher property taxes driven by increased investment.
•Interest and Investment income decreased by $7 million due to lower advances to affiliates.
•Interest Expense increased $13 million primarily due to higher long-term debt balances and interest rates.
•Income Tax Expense decreased $183 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 $62 million increase due to an increase in pretax book income.
•Equity Earnings of Unconsolidated Subsidiaries decreased $6 million due to lower pretax earnings by ETT and PATH-WV.
•Net Income Attributable to Noncontrolling Interests increased $87 million primarily due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.
30

GENERATION & MARKETING

Reconciliation of 2024 to 2025 Earnings Attributable to AEP Common Shareholders
(in millions)
  
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2024 Earnings Attributable to AEP Common Shareholders$93.3 $226.1 
  
Changes in Revenues: 
Merchant Generation27.3 66.6 
Renewable Generation(9.1)(24.7)
Retail, Trading and Marketing195.4 453.8 
Total Change in Revenues213.6 495.7 
  
Changes in Expenses and Other: 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation(211.3)(549.8)
Other Operation and Maintenance(14.8)29.0 
Asset Impairments and Other Related Charges— 76.2 
Depreciation and Amortization0.1 5.0 
Taxes Other Than Income Taxes0.1 (0.2)
Interest and Investment Income— (6.0)
Non-Service Cost Components of Net Periodic Benefit Cost(0.6)(1.5)
Interest Expense2.5 9.5 
Total Change in Expenses and Other(224.0)(437.8)
  
Income Tax Expense(38.6)(74.3)
Equity Earnings of Unconsolidated Subsidiaries— (0.9)
  
2025 Earnings Attributable to AEP Common Shareholders$44.3 $208.8 

Third Quarter of 2025 Compared to Third Quarter of 2024

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

•Merchant Generation increased $27 million primarily due to higher realized prices in 2025.
•Renewable Generation decreased $9 million primarily due to the sale of AEP OnSite Partners in September 2024.
•Retail, Trading and Marketing increased $195 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 $211 million primarily due to an increase in energy costs in 2025.
•Other Operation and Maintenance expenses increased $15 million primarily due to the gain on a solar contract termination agreement in 2024.
•Income Tax Expense increased $39 million primarily due to a decrease in amortization of deferred ITCs related to the sale of AEP OnSite Partners in September 2024.
31

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

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

•Merchant Generation increased $67 million primarily due to higher realized prices in 2025.
•Renewable Generation decreased $25 million primarily due to the sale of AEP OnSite Partners in September 2024.
•Retail, Trading and Marketing increased $454 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 $550 million primarily due to an increase in energy costs in 2025.
•Other Operation and Maintenance expenses decreased $29 million primarily due to renewable contract termination proceeds in 2025 and the sale of AEP OnSite Partners in September 2024.
•Asset Impairments and Other Related Charges decreased $76 million due to the Federal EPA’s revised CCR rules finalized in 2024.
•Depreciation and Amortization expenses decreased $5 million primarily due to the sale of AEP OnSite Partners in September 2024.
•Interest and Investment Income decreased $6 million primarily due to the sale of AEP OnSite Partners in September 2024.
•Interest Expense decreased $10 million due to lower advances from affiliates.
•Income Tax Expense increased $74 million primarily due to:
•A $54 million increase due to a decrease in amortization of deferred ITCs related to the sale of NMRD and AEP OnSite Partners in 2024.
•A $12 million increase due to an increase in pretax book income.

32

CORPORATE AND OTHER

Third Quarter of 2025 Compared to Third Quarter of 2024

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $165 million in 2024 to a loss of $118 million in 2025 primarily due to:

•A $28 million decrease in interest expense due to lower interest rates.
•A $23 million increase at EIS primarily due to decreased insurance reserves.
•A $19 million loss contingency recorded in 2024 associated with the SEC investigation.
•A $6 million increase in equity earnings.
These increases in earnings were partially offset by:
•A $15 million increase in Income Tax Expense primarily due to an increase in pretax book income.
•A $13 million decrease in interest income primarily due to lower advances to affiliates.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $288 million in 2024 to a loss of $215 million in 2025 primarily due to:

•A $41 million decrease in interest expense due to lower interest rates.
•A $19 million loss contingency recorded in 2024 associated with the SEC investigation.
•An $18 million increase in equity earnings.
•A $14 million increase in Income Tax Benefit primarily due to an increase in PTCs.
•An $11 million increase due to the recognition of deferred revenues for completed agreements.
These increases in earnings were partially offset by:
•A $29 million decrease in interest income primarily due to lower advances to affiliates.

AEP CONSOLIDATED INCOME TAXES

Third Quarter of 2025 Compared to Third Quarter of 2024

Income Tax Expense increased $101 million primarily due to:
•A $38 million increase due to a decrease in amortization of deferred ITCs related to the sale of AEP OnSite Partners in 2024.
•A $26 million increase due to an increase in pretax book income.
•A $13 million increase due to an increase in flow-through expense primarily driven by cost of removal.
•A $10 million increase due to a decrease in PTCs.
•A $7 million increase due to an increase in state taxes.
•A $7 million increase due to an increase in flow-through CAMT expense.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

Income Tax Benefit decreased $111 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 $184 million decrease due to an increase in pretax book income.
•A $54 million decrease due to a decrease in amortization of deferred ITCs related to the sale of NMRD and AEP OnSite Partners in 2024.
•A $32 million decrease due to a reduction in Excess ADIT regulatory liabilities as a result of the APSC’s denial of SWEPCo’s request to allow the merchant portion of the Turk Plant to serve Arkansas customers recorded in 2024.
•A $16 million decrease due to a decrease in amortization of Excess ADIT.
•A $13 million decrease due to an increase in flow-through expense primarily driven by cost of removal.
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 $37 million increase due to an increase in PTCs.

33

FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization
 September 30, 2025December 31, 2024
 (dollars in millions)
Long-term Debt, including amounts due within one year$46,137.6 58.6 %$42,642.8 59.1 %
Short-term Debt1,157.7 1.4 2,523.8 3.5 
Total Debt47,295.3 60.0 45,166.6 62.6 
AEP Common Equity30,389.3 38.6 26,943.8 37.3 
Noncontrolling Interests1,090.0 1.4 42.3 0.1 
Total Debt and Equity Capitalization$78,774.6 100.0 %$72,152.7 100.0 %

AEP’s ratio of debt-to-total capital decreased from 62.6% to 60.0% as of December 31, 2024 and September 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 AEP’s capital investment plan in addition to working capital needs.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity for the next twelve months and foreseeable future.  As of September 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 nine months ended September 30, 2025.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of September 30, 2025, available liquidity was approximately $6.8 billion as illustrated in the table below:

AmountMaturity
Commercial Paper Backup:(in millions)
Revolving Credit Facility$5,000.0 March 2029
Revolving Credit Facility1,000.0 March 2027
Cash and Cash Equivalents1,067.7  
Total Liquidity Sources7,067.7  
Less:AEP Commercial Paper Outstanding250.0  
Net Available Liquidity$6,817.7  


34

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries.  The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers.  The maximum amount of commercial paper outstanding during the first nine months of 2025 was $2.9 billion.  The weighted-average interest rate for AEP’s commercial paper for the nine months ended September 30, 2025 was 4.58%.

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 September 30, 2025 was $364 million with maturities ranging from October 2025 to September 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 2027. As of September 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 September 30, 2025, this contractually-defined percentage was 55.5%. Non-performance under these covenants could result in an event of default under these credit agreements.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $100 million, would cause an event of default under these credit agreements.  This condition also applies, at the more restrictive level of $50 million of debt outstanding, in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable.  However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

The revolving credit facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders and AEP manages its borrowings to stay within those authorized limits.

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 nine months ended September 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 $0.95 per share in October 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.


35

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.
36

CASH FLOW

AEP relies primarily on cash flows from operations, debt issuances, issuances of common stock and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper and bank term loans, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.
Nine Months Ended 
September 30,
 20252024
 (in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period$246.0 $379.0 
Net Cash Flows from Operating Activities5,130.8 5,076.9 
Net Cash Flows Used for Investing Activities(7,749.1)(4,769.5)
Net Cash Flows from (Used for) Financing Activities3,479.1 (387.2)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash860.8 (79.8)
Cash, Cash Equivalents and Restricted Cash at End of Period$1,106.8 $299.2 

Operating Activities
Nine Months Ended 
September 30,
20252024
(in millions)
Net Income$3,090.8 $2,309.9 
Non-Cash Adjustments to Net Income (a)2,516.8 2,540.7 
Mark-to-Market of Risk Management Contracts(192.6)(97.6)
Pension Contributions to Qualified Plan Trust(94.7)— 
Property Taxes541.3 508.3 
Deferred Fuel Over/Under-Recovery, Net164.7 304.6 
Change in Other Noncurrent Assets(719.7)(244.0)
Change in Other Noncurrent Liabilities133.8 193.8 
Change in Certain Components of Working Capital(309.6)(438.8)
Net Cash Flows from Operating Activities$5,130.8 $5,076.9 

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

Net Cash Flows from Operating Activities increased by $54 million primarily due to the following:
•A $757 million increase in cash from Net Income, after non-cash adjustments. See “Results of Operations” for further detail.
This increase in cash was partially offset by:
•A $476 million decrease in cash from Change in Other Noncurrent Assets primarily due to timing differences in collections from customers under rate rider mechanisms, including storm restoration expenses incurred in several jurisdictions. See Note 4 - Rate Matters for additional information.
•A $140 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.

37

Investing Activities
Nine Months Ended 
September 30,
 20252024
 (in millions)
Construction Expenditures$(6,001.2)$(5,168.6)
Acquisitions of Generation Facilities(1,657.3)— 
Acquisitions of Nuclear Fuel(88.9)(98.4)
Proceeds from Sales of Assets12.6 365.0 
Proceeds from Sale of Equity Method Investment— 114.0 
Other(14.3)18.5 
Net Cash Flows Used for Investing Activities$(7,749.1)$(4,769.5)

Net Cash Flows Used for Investing Activities increased by $3 billion primarily due to the following:
•A $1.7 billion increase due to the acquisitions of Green Country Power Plant, Pixley Solar Energy Facility, Flat Ridge IV Wind Energy Facility and Flat Ridge V Wind Energy Facility. See “Acquisitions” section of Note 6 for additional information.
•An $833 million increase in Construction Expenditures primarily due to increases in Vertically Integrated Utilities of $409 million and Transmission and Distribution Utilities of $348 million.
•A $352 million decrease in Proceeds from Sales of Assets primarily due to the sale of AEP OnSite Partners in 2024. See “Dispositions” section of Note 6 for additional information.
•A $114 million decrease in Proceeds from Sale of Equity Method Investment. See “Dispositions” section of Note 6 for additional information.

Financing Activities
Nine Months Ended 
September 30,
 20252024
 (in millions)
Issuance of Common Stock$187.5 $513.0 
Issuance/Retirement of Debt, Net2,079.3 608.8 
Principal Payments for Finance Lease Obligations(37.9)(51.2)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs2,782.9 — 
Dividends Paid on Common Stock(1,497.9)(1,402.7)
Other(34.8)(55.1)
Net Cash Flows from (Used for) Financing Activities$3,479.1 $(387.2)

Net Cash Flows from (Used for) Financing Activities increased by $3.9 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 $2.5 billion increase in issuances of long-term debt. See Note 13 - Financing Activities for additional information.
These increases in cash were partially offset by:
•An $835 million increase in retirements of long-term debt. See Note 13 - Financing Activities for additional information.
•A $326 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 September 30, 2025 through October 29, 2025, the date that the third quarter Form 10-Q was filed.
38

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $11.9 billion of capital expenditures in 2025.  For the five-year period, 2026 through 2030, management forecasts capital expenditures of $72 billion. Management’s forecasted capital expenditures reflect planned investments for transmission infrastructure and new generation resources to support existing customers and forecasted large load increases and continued improvements in distribution system reliability.

Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews, inflation and the ability to access capital.  Management has funded, or expects to fund, these capital expenditures through cash flows from operations and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged.

The 2026-2030 estimated capital expenditures by Business Segment are as follows:
Segment2026-2030 Budgeted Capital Expenditures
(in millions)
Vertically Integrated Utilities$37,155 
Transmission and Distribution Utilities22,537 
AEP Transmission Holdco10,607 
Generation & Marketing111 
Corporate and Other1,556 
     Total$71,966 

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.

39

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, Senior Vice President of Regulated Commercial Operations, President AEP Transmission, and Senior Vice President Finance. The Competitive Risk Committee consists of AEPSC’s Chief Financial Officer, Executive Vice President and Chief Commercial Officer, Senior Vice President and Treasurer, and Senior Vice President of Competitive Commercial Operations.  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.


40

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

MTM Derivative Contract Net Assets (Liabilities)
Nine Months Ended September 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
(74.4)— (33.2)(107.6)
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)
(14.7)— 63.2 48.5 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)218.1 3.8 — 221.9 
Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of September 30, 2025
$220.8 $(44.2)$202.5 379.1 
Commodity Cash Flow Hedge Contracts
 97.3 
Fair Value Hedge Contracts  (49.0)
Collateral Deposits  (64.5)
Total MTM Derivative Contract Net Assets as of September 30, 2025
  $362.9 

(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 September 30, 2025, credit exposure net of collateral to sub investment grade counterparties was approximately 10.24%, 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).


41

As of September 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 QualityExposure
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$585.9 $69.8 $516.1 3 $313.8 
Non-investment Grade5.4 0.9 4.5 2 4.5 
No External Ratings:  
Internal Investment Grade13.9 — 13.9 2 8.9 
Internal Non-investment Grade129.8 73.8 56.0 2 48.8 
Total as of September 30, 2025$735.0 $144.5 $590.5 

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 September 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.

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

VaR Model
Trading Portfolio
Nine Months EndedTwelve Months Ended
September 30, 2025December 31, 2024
EndHighAverageLowEndHighAverageLow
(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
Nine Months EndedTwelve Months Ended
September 30, 2025December 31, 2024
EndHighAverageLowEndHighAverageLow
(in millions)(in millions)
$1.6 $28.8 $9.8 $1.6 $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.


42

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

Interest Rate Risk

AEP is exposed to interest rate market fluctuations in the normal course of business operations. Prior to 2022, interest rates remained at low levels and the Federal Reserve maintained the federal funds target range at 0.0% to 0.25% for much of 2021. During 2022 and 2023, the Federal Reserve approved 11 rate increases for a total cumulative increase of 5.25%. In light of the progress on inflation and the balance of risks, the Federal Reserve authorized three rate cuts in 2024, totaling a cumulative decrease of 1.0%. In September 2025, the Federal Reserve approved an additional 0.25% rate cut. 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 nine months ended September 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 $30 million and $21 million, respectively.
43


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions, except per-share and share amounts)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
2025202420252024
REVENUES
Vertically Integrated Utilities$3,511.2 $3,248.8 $9,531.2 $8,722.0 
Transmission and Distribution Utilities1,680.2 1,568.5 4,638.3 4,480.5 
Generation & Marketing693.8 483.7 1,975.4 1,442.1 
Other Revenues125.2 119.1 415.8 380.4 
TOTAL REVENUES6,010.4 5,420.1 16,560.7 15,025.0 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation1,980.2 1,659.2 5,374.5 4,603.5 
Other Operation797.8 805.8 2,087.8 2,385.4 
Maintenance405.1 343.7 1,114.3 1,012.7 
Asset Impairments and Other Related Charges— — — 142.5 
Depreciation and Amortization879.6 852.7 2,566.1 2,461.7 
Taxes Other Than Income Taxes426.3 407.2 1,213.3 1,211.2 
TOTAL EXPENSES4,489.0 4,068.6 12,356.0 11,817.0 
OPERATING INCOME1,521.4 1,351.5 4,204.7 3,208.0 
Other Income (Expense):    
Other Income12.1 28.5 35.4 55.2 
Allowance for Equity Funds Used During Construction58.5 54.2 172.9 153.0 
Non-Service Cost Components of Net Periodic Benefit Cost34.4 46.5 104.1 129.0 
Interest Expense(508.5)(498.8)(1,492.9)(1,400.0)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS1,117.9 981.9 3,024.2 2,145.2 
Income Tax Expense (Benefit)138.7 37.5 13.3 (97.7)
Equity Earnings of Unconsolidated Subsidiaries21.1 17.3 79.9 67.0 
NET INCOME1,000.3 961.7 3,090.8 2,309.9 
Net Income Attributable to Noncontrolling Interests28.3 2.1 92.8 6.9 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$972.0 $959.6 $2,998.0 $2,303.0 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING534,867,357 532,208,876 534,186,206 529,230,818 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$1.82 $1.80 $5.61 $4.35 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING537,988,799 533,600,842 536,364,715 530,456,985 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$1.81 $1.80 $5.59 $4.34 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
44

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
Three Months Ended September 30,Nine Months Ended September 30,
2025202420252024
Net Income$1,000.3 $961.7 $3,090.8 $2,309.9 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES    
Cash Flow Hedges, Net of Tax of $(4.1) and $(12.3) for the Three Months Ended September 30, 2025 and 2024, Respectively, and $(6.8) and $(8.0) for the Nine Months Ended September 30, 2025 and 2024, Respectively
(15.4)(46.3)(25.5)(30.1)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0.1 and $(0.1) for the Three Months Ended September 30, 2025 and 2024, Respectively, and $0.2 and $(0.3) for the Nine Months Ended September 30, 2025 and 2024, Respectively
0.2 (0.6)0.8 (1.3)
TOTAL OTHER COMPREHENSIVE LOSS(15.2)(46.9)(24.7)(31.4)
TOTAL COMPREHENSIVE INCOME985.1 914.8 3,066.1 2,278.5 
Total Comprehensive Income Attributable To Noncontrolling Interests28.3 2.1 92.8 6.9 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$956.8 $912.7 $2,973.3 $2,271.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
45

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
AEP Common Shareholders
Common StockAccumulated
Other
Comprehensive
Income (Loss)
SharesAmountPaid-in
Capital		Retained
Earnings		Noncontrolling
Interests		Total
TOTAL EQUITY – DECEMBER 31, 2023527.4 $3,427.9 $9,073.9 $12,800.4 $(55.5)$39.2 $25,285.9 
Issuance of Common Stock0.8 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, 2024528.2 3,433.3 9,094.3 13,338.0 (62.3)40.4 25,843.7 
Issuance of Common Stock4.9 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, 2024533.1 3,465.4 9,498.5 13,211.3 (40.0)40.5 26,175.7 
Issuance of Common Stock0.6 3.3 33.9 37.2 
Common Stock Dividends(470.2)(a)(1.2)(471.4)
Other Changes in Equity2.5 2.5 
Net Income959.6 2.1 961.7 
Other Comprehensive Loss(46.9)(46.9)
TOTAL EQUITY – SEPTEMBER 30, 2024533.7 $3,468.7 $9,534.9 $13,700.7 $(86.9)$41.4 $26,658.8 
TOTAL EQUITY – DECEMBER 31, 2024534.1 $3,471.6 $9,606.1 $13,869.2 $(3.1)$42.3 $26,986.1 
Issuance of Common Stock1.1 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 Income800.2 2.0 802.2 
Other Comprehensive Income23.4 23.4 
TOTAL EQUITY – MARCH 31, 2025535.2 3,478.7 9,652.3 14,169.4 20.3 43.3 27,364.0 
Issuance of Common Stock0.6 3.7 52.7 56.4 
Common Stock Dividends(498.5)(b)(1.0)(499.5)
Other Changes in Equity9.1 0.1 9.2 
Midwest Transmission Holdings Noncontrolling Interest Transaction1,790.5 992.4 2,782.9 
Net Income1,225.8 62.5 1,288.3 
Other Comprehensive Loss(32.9)(32.9)
TOTAL EQUITY – JUNE 30, 2025535.8 3,482.4 11,504.6 14,896.7 (12.6)1,097.3 30,968.4 
Issuance of Common Stock0.5 3.6 52.1 55.7 
Capital Contribution from Noncontrolling Interest33.9 33.9 
Common Stock Dividends(499.4)(b)(499.4)
Dividends Paid to Noncontrolling Interest(69.5)(69.5)
Other Changes in Equity5.1 5.1 
Net Income972.0 28.3 1,000.3 
Other Comprehensive Loss    (15.2) (15.2)
TOTAL EQUITY – SEPTEMBER 30, 2025536.3 $3,486.0 $11,561.8 $15,369.3 $(27.8)$1,090.0 $31,479.3 

(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 110.
46

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
 September 30,December 31,
 20252024
CURRENT ASSETS  
Cash and Cash Equivalents$1,067.7 $202.9 
Restricted Cash
(September 30, 2025 and December 31, 2024 Amounts Include $39.1 and $43.1, Respectively, Related to Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding and Cost Recovery Funding)
39.1 43.1 
Other Temporary Investments
(September 30, 2025 and December 31, 2024 Amounts Include $215.2 and $206.7, Respectively, Related to EIS)
225.4 215.4 
Accounts Receivable:  
Customers1,141.4 1,100.1 
Accrued Unbilled Revenues355.0 367.0 
Pledged Accounts Receivable – AEP Credit1,336.2 1,161.5 
Miscellaneous63.2 64.1 
Allowance for Credit Losses(62.7)(60.8)
Total Accounts Receivable2,833.1 2,631.9 
Fuel599.0 748.9 
Materials and Supplies986.7 966.2 
Risk Management Assets407.9 210.4 
Accrued Tax Benefits59.7 38.2 
Regulatory Asset for Under-Recovered Fuel Costs380.6 445.9 
Prepayments and Other Current Assets260.8 285.9 
TOTAL CURRENT ASSETS6,860.0 5,788.8 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation26,442.2 24,829.7 
Transmission40,987.3 38,871.9 
Distribution32,618.2 31,061.9 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)8,385.1 7,491.6 
Construction Work in Progress7,456.7 6,346.9 
Total Property, Plant and Equipment115,889.5 108,602.0 
Accumulated Depreciation and Amortization27,871.8 26,186.4 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET88,017.7 82,415.6 
OTHER NONCURRENT ASSETS  
Regulatory Assets4,950.2 5,129.2 
Securitized Assets952.9 554.3 
Spent Nuclear Fuel and Decommissioning Trusts4,858.9 4,395.1 
Goodwill52.5 52.5 
Long-term Risk Management Assets264.6 289.1 
Operating Lease Assets578.2 580.1 
Deferred Charges and Other Noncurrent Assets3,718.5 3,873.3 
TOTAL OTHER NONCURRENT ASSETS15,375.8 14,873.6 
TOTAL ASSETS$110,253.5 $103,078.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
47

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2025 and December 31, 2024
(in millions, except per-share and share amounts)
(Unaudited)
   September 30,December 31,
 20252024
CURRENT LIABILITIES  
Accounts Payable$2,806.7 $2,637.6 
Short-term Debt:  
Securitized Debt for Receivables – AEP Credit900.0 900.0 
Other Short-term Debt257.7 1,623.8 
Total Short-term Debt1,157.7 2,523.8 
Long-term Debt Due Within One Year
(September 30, 2025 and December 31, 2024 Amounts Include $178.8 and $216.5, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)
1,898.6 3,335.0 
Risk Management Liabilities122.7 100.0 
Customer Deposits498.5 454.7 
Accrued Taxes1,257.2 1,922.1 
Accrued Interest606.4 453.3 
Obligations Under Operating Leases98.4 91.9 
Other Current Liabilities1,551.4 1,490.9 
TOTAL CURRENT LIABILITIES9,997.6 13,009.3 
NONCURRENT LIABILITIES  
Long-term Debt
(September 30, 2025 and December 31, 2024 Amounts Include $1,295.7 and $826.5, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)
44,239.0 39,307.8 
Long-term Risk Management Liabilities186.9 224.4 
Deferred Income Taxes10,713.9 9,972.4 
Regulatory Liabilities and Deferred Investment Tax Credits8,320.0 8,344.0 
Asset Retirement Obligations3,647.1 3,530.6 
Employee Benefits and Pension Obligations268.1 360.7 
Obligations Under Operating Leases496.3 504.3 
Deferred Credits and Other Noncurrent Liabilities844.6 800.6 
TOTAL NONCURRENT LIABILITIES68,715.9 63,044.8 
TOTAL LIABILITIES78,713.5 76,054.1 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
MEZZANINE EQUITY
Contingently Redeemable Performance Share Awards60.7 37.8 
TOTAL MEZZANINE EQUITY60.7 37.8 
EQUITY  
Common Stock – Par Value – $6.50 Per Share:
  
20252024  
Shares Authorized600,000,000600,000,000  
Shares Issued536,312,729534,094,530  
(1,186,815 Shares were Held in Treasury as of September 30, 2025 and December 31, 2024, Respectively)
3,486.0 3,471.6 
Paid-in Capital11,561.8 9,606.1 
Retained Earnings15,369.3 13,869.2 
Accumulated Other Comprehensive Income (Loss)(27.8)(3.1)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY30,389.3 26,943.8 
Noncontrolling Interests1,090.0 42.3 
TOTAL EQUITY31,479.3 26,986.1 
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY$110,253.5 $103,078.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
48

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20252024
OPERATING ACTIVITIES  
Net Income$3,090.8 $2,309.9 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization2,566.1 2,461.7 
Deferred Income Taxes123.6 89.5 
Asset Impairments and Other Related Charges— 142.5 
Allowance for Equity Funds Used During Construction(172.9)(153.0)
Mark-to-Market of Risk Management Contracts(192.6)(97.6)
Pension Contributions to Qualified Plan Trust(94.7)— 
Property Taxes541.3 508.3 
Deferred Fuel Over/Under-Recovery, Net164.7 304.6 
Change in Other Noncurrent Assets(719.7)(244.0)
Change in Other Noncurrent Liabilities133.8 193.8 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(212.4)(131.8)
Fuel, Materials and Supplies150.7 188.5 
Accounts Payable327.3 14.2 
Accrued Taxes, Net(687.2)(532.3)
Other Current Assets37.7 (139.2)
Other Current Liabilities74.3 161.8 
Net Cash Flows from Operating Activities5,130.8 5,076.9 
INVESTING ACTIVITIES  
Construction Expenditures(6,001.2)(5,168.6)
Purchases of Investment Securities(2,407.0)(2,398.0)
Sales of Investment Securities2,349.2 2,343.5 
Acquisitions of Generation Facilities(1,657.3)— 
Acquisitions of Nuclear Fuel(88.9)(98.4)
Proceeds from Sales of Assets12.6 365.0 
Proceeds from Sale of Equity Method Investment— 114.0 
Other Investing Activities43.5 73.0 
Net Cash Flows Used for Investing Activities(7,749.1)(4,769.5)
FINANCING ACTIVITIES  
Capital Contribution from Noncontrolling Interest33.9 — 
Issuance of Common Stock187.5 513.0 
Issuance of Long-term Debt6,249.2 3,748.5 
Issuance of Short-term Debt with Original Maturities greater than 90 Days319.9 376.6 
Change in Short-term Debt with Original Maturities less than 90 Days, Net(1,008.2)(676.1)
Retirement of Long-term Debt(2,803.8)(1,969.1)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days(677.8)(871.1)
Principal Payments for Finance Lease Obligations(37.9)(51.2)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs2,782.9 — 
Dividends Paid on Common Stock(1,497.9)(1,402.7)
Dividends Paid to Noncontrolling Interest(71.5)(4.7)
Other Financing Activities2.8 (50.4)
Net Cash Flows from (Used for) Financing Activities3,479.1 (387.2)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash860.8 (79.8)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period246.0 379.0 
Cash, Cash Equivalents and Restricted Cash at End of Period$1,106.8 $299.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
49

AEP TEXAS INC. AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months Ended 
September 30,		Nine Months Ended 
September 30,
 2025202420252024
 (in millions of KWhs)
Retail:  
Residential4,135 4,116 10,326 10,174 
Commercial5,219 4,283 14,037 11,733 
Industrial3,489 3,181 10,159 9,778 
Miscellaneous186 189 477 496 
Total Retail13,029 11,769 34,999 32,181 


Summary of Heating and Cooling Degree Days
 Three Months Ended 
September 30,		Nine Months Ended 
September 30,
 2025202420252024
 (in degree days)
Actual – Heating— — 296 162 
Normal – Heating— — 208 198 
Actual – Cooling1,367 1,457 2,520 2,801 
Normal – Cooling1,348 1,401 2,369 2,487 










50

AEP Texas Inc. and Subsidiaries
Reconciliation of 2024 to 2025 Net Income
(in millions)
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2024 Net Income$132.5 $340.6 
  
Changes in Revenues:
Retail Revenues46.3 128.2 
Transmission Revenues13.7 21.7 
Other Revenues(12.1)(53.8)
Total Change in Revenues47.9 96.1 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(23.3)(75.4)
Depreciation and Amortization13.4 39.3 
Taxes Other Than Income Taxes(1.1)(6.0)
Interest Income(2.5)(4.5)
Allowance for Equity Funds Used During Construction2.6 2.5 
Non-Service Cost Components of Net Periodic Benefit Cost1.8 5.8 
Interest Expense1.3 (11.7)
Total Change in Expenses and Other(7.8)(50.0)
  
Income Tax Expense(5.9)2.7 
  
2025 Net Income$166.7 $389.4 

Third Quarter of 2025 Compared to Third Quarter of 2024

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

•Retail Revenues increased $46 million primarily due to the following:
•A $43 million increase in base case and rider revenues.
•A $3 million increase in weather-normalized revenues primarily in the residential class.
•Transmission Revenues increased $14 million primarily due to the following:
•A $28 million increase in interim rates driven by increased transmission investments.
This increase was partially offset by:
•A $14 million decrease due to lower peak loads included in the 2025 billing rates.
•Other Revenues decreased $12 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 $23 million primarily due to the following:
•A $15 million increase in recoverable transmission expenses.
•A $4 million increase in distribution expenses.
•Depreciation and Amortization expenses decreased $13 million primarily due to the following:
•A $19 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.
•A $6 million decrease due to the deferral of eligible costs related to the UTM.
These decreases were partially offset by:
•A $9 million increase due to a higher depreciable base.
•Income Tax Expense increased $6 million primarily due to an increase in pretax book income.
51

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

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

•Retail Revenues increased $128 million primarily due to the following:
•A $119 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, partially offset by a 10% decrease in cooling degree days.
These increases were partially offset by:
•A $3 million decrease in weather-normalized revenues primarily in the residential class.
•Transmission Revenues increased $22 million primarily due to the following:
•A $70 million increase in interim rates driven by increased transmission investments.
This increase was partially offset by:
•A $48 million decrease due to lower peak loads included in the 2025 billing rates.
•Other Revenues decreased $54 million primarily due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $75 million primarily due to the following:
•A $57 million increase in recoverable transmission expenses.
•A $16 million increase in transmission and distribution 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 $39 million primarily due to the following:
•A $51 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.
•A $17 million decrease due to the deferral of eligible costs related to the UTM.
These decreases were partially offset by:
•A $28 million increase due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $6 million primarily due to higher property taxes driven by increased investment.
•Non-Service Cost Components of Net Periodic Benefit Costs decreased $6 million primarily due to the deferral of OPEB and Pension costs beginning in October 2024.
•Interest Expense increased $12 million primarily due to the following:
•A $24 million increase due to higher debt balances and interest rates.
•A $5 million increase due to a decrease in the debt component of AFUDC.
These increases were partially offset by:
•A $19 million decrease due to the deferral of eligible costs related to the UTM.
52


AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
  2025 202420252024
REVENUES    
Electric Transmission and Distribution $615.6 $569.2 $1,663.9 $1,569.9 
Sales to AEP Affiliates 1.3 1.3 4.0 4.0 
Other Revenues 2.2 0.7 5.4 3.3 
TOTAL REVENUES 619.1 571.2 1,673.3 1,577.2 
 
EXPENSES     
Other Operation 186.9 164.7 516.9 453.3 
Maintenance 23.6 22.5 78.1 66.3 
Depreciation and Amortization 113.3 126.7 329.0 368.3 
Taxes Other Than Income Taxes 45.9 44.8 131.4 125.4 
TOTAL EXPENSES 369.7 358.7 1,055.4 1,013.3 
 
OPERATING INCOME 249.4 212.5 617.9 563.9 
 
Other Income (Expense):     
Interest Income 0.6 3.1 1.2 5.7 
Allowance for Equity Funds Used During Construction13.1 10.5 37.1 34.6 
Non-Service Cost Components of Net Periodic Benefit Cost5.5 3.7 16.6 10.8 
Interest Expense (66.4)(67.7)(200.2)(188.5)
 
INCOME BEFORE INCOME TAX EXPENSE 202.2 162.1 472.6 426.5 
 
Income Tax Expense 35.5 29.6 83.2 85.9 
NET INCOME $166.7 $132.5 $389.4 $340.6 
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
53

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
September 30,September 30,
2025202420252024
Net Income$166.7 $132.5 $389.4 $340.6 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2025 and 2024, Respectively, and $(0.1) and $1.6 for the Nine Months Ended September 30, 2025 and 2024, Respectively
(0.1)(0.1)(0.5)6.0 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)(0.1)(0.1)(0.5)6.0 
TOTAL COMPREHENSIVE INCOME$166.6 $132.4 $388.9 $346.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

54

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 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 Income79.7 79.7 
Other Comprehensive Income3.9 3.9 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2024
2,079.6 2,804.8 (4.7)4,879.7 
Capital Contribution from Parent1.6  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 
Return of Capital to Parent(0.7)(0.7)
Common Stock Dividends(150.0)(150.0)
Net Income132.5 132.5 
Other Comprehensive Loss(0.1)(0.1)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2024
$2,080.5 $2,915.7 $(2.6)$4,993.6 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024
$2,092.4 $2,795.2 $(3.0)$4,884.6 
Net Income101.6 101.6 
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 Parent250.5 250.5 
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 
Capital Contribution from Parent200.4 200.4 
Net Income166.7 166.7 
Other Comprehensive Loss(0.1)(0.1)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2025
$2,543.3 $3,184.6 $(3.5)$5,724.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

55

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
  September 30,December 31,
  2025 2024
CURRENT ASSETS    
Cash and Cash Equivalents$0.1 $0.1 
Restricted Cash
(September 30, 2025 and December 31, 2024 Amounts Include $7.3 and $23.5, Respectively, Related to Transition Funding and Restoration Funding)
7.3 23.5 
Advances to Affiliates425.3 7.2 
Accounts Receivable:   
Customers 233.1 182.8 
Affiliated Companies 11.7 10.7 
Accrued Unbilled Revenues122.8 97.2 
Miscellaneous 0.1 0.3 
Allowance for Credit Losses(4.1)(4.3)
Total Accounts Receivable 363.6 286.7 
Materials and Supplies 149.8 169.5 
Prepayments and Other Current Assets 19.6 13.4 
TOTAL CURRENT ASSETS 965.7 500.4 
 
PROPERTY, PLANT AND EQUIPMENT   
Electric:   
Transmission
 8,008.7 7,546.2 
Distribution
 6,642.3 6,250.5 
Other Property, Plant and Equipment 1,203.1 1,175.7 
Construction Work in Progress 1,441.2 1,118.0 
Total Property, Plant and Equipment 17,295.3 16,090.4 
Accumulated Depreciation and Amortization 2,177.7 2,046.9 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 15,117.6 14,043.5 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 396.3 353.6 
Securitized Assets
(September 30, 2025 and December 31, 2024 Amounts Include $99.4 and $116.7, Respectively, Related to Restoration Funding)
99.4 116.7 
Operating Lease Assets51.7 54.4 
Deferred Charges and Other Noncurrent Assets 181.8 131.0 
TOTAL OTHER NONCURRENT ASSETS 729.2 655.7 
 
TOTAL ASSETS $16,812.5 $15,199.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
56

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
  September 30,December 31,
  2025 2024
CURRENT LIABILITIES 
Advances from Affiliates $— $284.9 
Accounts Payable: 
General 399.7 366.2 
Affiliated Companies 28.4 34.9 
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2025 and December 31, 2024 Amounts Include $25.0 and $24.4, Respectively, Related to Restoration Funding)
325.0 324.5 
Accrued Taxes 143.8 127.1 
Accrued Interest
(September 30, 2025 and December 31, 2024 Amounts Include $0.2 and $1.9, Respectively, Related to Restoration Funding)
101.7 55.0 
Obligations Under Operating Leases14.2 13.1 
Other Current Liabilities 246.0 201.4 
TOTAL CURRENT LIABILITIES 1,258.8 1,407.1 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated
(September 30, 2025 and December 31, 2024 Amounts Include $77.6 and $102.4, Respectively, Related to Restoration Funding)
6,939.5 6,117.1 
Deferred Income Taxes 1,418.4 1,322.7 
Regulatory Liabilities and Deferred Investment Tax Credits 1,295.8 1,285.4 
Obligations Under Operating Leases39.8 43.4 
Deferred Credits and Other Noncurrent Liabilities 135.8 139.3 
TOTAL NONCURRENT LIABILITIES 9,829.3 8,907.9 
 
TOTAL LIABILITIES 11,088.1 10,315.0 
 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5) 
 
COMMON SHAREHOLDER’S EQUITY   
Paid-in Capital 2,543.3 2,092.4 
Retained Earnings 3,184.6 2,795.2 
Accumulated Other Comprehensive Income (Loss)(3.5)(3.0)
TOTAL COMMON SHAREHOLDER’S EQUITY 5,724.4 4,884.6 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $16,812.5 $15,199.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
57

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  2025 2024
OPERATING ACTIVITIES    
Net Income $389.4 $340.6 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:   
Depreciation and Amortization 329.0 368.3 
Deferred Income Taxes 67.8 70.3 
Allowance for Equity Funds Used During Construction(37.1)(34.6)
Pension Contributions to Qualified Plan Trust(12.0)— 
Change in Other Noncurrent Assets (116.2)(99.3)
Change in Other Noncurrent Liabilities 49.1 32.0 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (76.9)(67.8)
Materials and Supplies 19.7 11.8 
Accounts Payable 38.7 23.6 
Accrued Taxes, Net15.5 56.0 
Other Current Assets (0.1)(9.1)
Other Current Liabilities 27.6 43.8 
Net Cash Flows from Operating Activities 694.5 735.6 
 
INVESTING ACTIVITIES   
Construction Expenditures (1,331.8)(1,042.4)
Change in Advances to Affiliates, Net(418.1)(54.7)
Other Investing Activities56.4 44.2 
Net Cash Flows Used for Investing Activities (1,693.5)(1,052.9)
 
FINANCING ACTIVITIES   
Capital Contribution from Parent450.9 1.6 
Return of Capital to Parent— (0.7)
Issuance of Long-term Debt – Nonaffiliated1,293.5 841.9 
Change in Advances from Affiliates, Net (284.9)(103.7)
Retirement of Long-term Debt – Nonaffiliated (474.5)(256.5)
Principal Payments for Finance Lease Obligations (5.6)(5.6)
Dividends Paid on Common Stock — (150.0)
Other Financing Activities3.4 1.4 
Net Cash Flows from Financing Activities 982.8 328.4 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash (16.2)11.1 
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 23.6 34.1 
Cash, Cash Equivalents and Restricted Cash at End of Period $7.4 $45.2 
 
SUPPLEMENTARY INFORMATION   
Cash Paid for Interest, Net of Capitalized Amounts $143.3 $132.8 
Net Cash Paid (Received) for Income Taxes 33.4 (2.7)
Noncash Acquisitions Under Finance Leases 5.2 3.6 
Construction Expenditures Included in Current Liabilities as of September 30, 259.3 167.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
58

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Summary of Investment in Transmission Assets for AEPTCo
As of September 30,
20252024
(in millions)
Plant In Service$16,470.9 $14,720.4 
Construction Work in Progress2,097.6 2,188.6 
Accumulated Depreciation and Amortization1,839.8 1,509.4 
Total Transmission Property, Net$16,728.7 $15,399.6 

AEP Transmission Company, LLC and Subsidiaries
Reconciliation of 2024 to 2025
Earnings Attributable to AEPTCo Common Shareholder
(in millions)
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2024 Earnings Attributable to Common Shareholder$191.3 $548.2 
Changes in Transmission Revenues:
Transmission Revenues60.8 371.7 
Total Change in Transmission Revenues60.8 371.7 
Changes in Expenses and Other:
Other Operation and Maintenance(12.5)(8.9)
Depreciation and Amortization(13.1)(33.5)
Taxes Other Than Income Taxes(6.2)(7.2)
Interest Income(1.8)(6.2)
Allowance for Equity Funds Used During Construction(3.5)— 
Interest Expense(7.0)(12.4)
Total Change in Expenses and Other(44.1)(68.2)
Income Tax Expense(2.5)181.8 
Net Income Attributable to Noncontrolling Interest(26.6)(87.3)
2025 Earnings Attributable to Common Shareholder$178.9 $946.2 

Third Quarter of 2025 Compared to Third 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 $61 million primarily due to continued transmission investment.


59

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

•Operation and Maintenance expenses increased $13 million primarily due to an increase in employee-related expenses, vegetation management expenses and other miscellaneous expenses.
•Depreciation and Amortization expenses increased $13 million primarily due to a higher depreciable base.
•Taxes Other than Income Taxes increased $6 million primarily due to higher property taxes driven by higher transmission investment.
•Interest Expense increased $7 million primarily due to higher long-term debt balances and interest rates.
•Net Income Attributable to Noncontrolling Interest increased $27 million due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 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 $372 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 $158 million increase due to continued transmission investment.

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

•Operation and Maintenance expenses increased $9 million primarily due to an increase in vegetation management expenses, affiliated rent expense and other miscellaneous expenses, partially offset by a 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 $34 million due to a higher depreciable base.
•Taxes Other than Income Taxes increased $7 million primarily due to higher property taxes driven by increased transmission investment.
•Interest Income decreased $6 million primarily due to lower advances to affiliates.
•Interest Expense increased $12 million primarily due to higher long-term debt balances and interest rates.
•Income Tax Expense decreased $182 million primarily due to the following:
•A $254 million decrease due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
This decrease was partially offset by:
•A $64 million increase due to an increase in pretax book income.
•Net Income Attributable to Noncontrolling Interest increased $87 million due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.


60


AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
2025 2024 2025 2024
REVENUES
Transmission Revenues$107.9 $103.3 $324.6 $299.0 
Sales to AEP Affiliates450.1 404.4 1,350.2 1,188.2 
(Provision for)/Reversal of – Revenue Refund – Affiliated— (8.5)119.8 (31.1)
(Provision for)/ Reversal of – Revenue Refund – Nonaffiliated— (2.2)32.2 (3.9)
Other Revenues— 0.2 0.1 3.0 
TOTAL REVENUES558.0 497.2 1,826.9 1,455.2 
EXPENSES    
Other Operation41.3 31.7 106.1 101.6 
Maintenance8.6 5.7 20.4 16.0 
Depreciation and Amortization121.3 108.2 354.3 320.8 
Taxes Other Than Income Taxes85.9 79.7 235.8 228.6 
TOTAL EXPENSES257.1 225.3 716.6 667.0 
OPERATING INCOME300.9 271.9 1,110.3 788.2 
Other Income (Expense):    
Interest Income – Affiliated1.3 3.1 3.1 9.3 
Allowance for Equity Funds Used During Construction20.8 24.3 64.7 64.7 
Interest Expense(61.3)(54.3)(172.9)(160.5)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)261.7 245.0 1,005.2 701.7 
Income Tax Expense (Benefit)56.2 53.7 (28.3)153.5 
NET INCOME205.5 191.3 1,033.5 548.2 
Net Income Attributable to Noncontrolling Interest26.6 — 87.3 — 
EARNINGS ATTRIBUTABLE TO AEPTCo COMMON SHAREHOLDER$178.9 $191.3 $946.2 $548.2 
AEPTCo is wholly-owned by AEP Transmission Holdco.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
61

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Nine Months Ended September 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 Member25.0 25.0 
Dividends Paid to AEP Member(40.0)(40.0)
Net Income 181.2 181.2 
TOTAL MEMBER'S EQUITY – MARCH 31, 20243,068.4 3,431.1 — 6,499.5 
Capital Contribution from AEP Member9.6 9.6 
Dividends Paid to AEP Member(31.0)(31.0)
Net Income175.7 175.7 
TOTAL MEMBER'S EQUITY – JUNE 30, 20243,078.0 3,575.8 — 6,653.8 
Return of Capital to AEP Member (4.5)(4.5)
Dividends Paid to AEP Member(26.0)(26.0)
Net Income 191.3 191.3 
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2024 $3,073.5 $3,741.1 $— $6,814.6 
  
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2024 $3,100.6 $3,850.3 $— $6,950.9 
Capital Contribution from AEP Member32.5 32.5 
Dividends Paid to AEP Member(42.5)(42.5)
Net Income211.5 211.5 
TOTAL MEMBER'S EQUITY – MARCH 31, 20253,133.1 4,019.3 — 7,152.4 
  
Capital Contribution from AEP Member8.3 8.3 
Dividends Paid to AEP Member(2,835.8)(2,835.8)
Midwest Transmission Holdings Noncontrolling Interest Transaction1,790.5 992.4 2,782.9 
Net Income555.8 60.7 616.5 
TOTAL MEMBER'S EQUITY – JUNE 30, 20254,931.9 1,739.3 1,053.1 7,724.3 
Capital Contribution from AEP Member 2.1 2.1 
Capital Contribution from Noncontrolling Interest33.9 33.9 
Dividends Paid to AEP Member(184.3)(184.3)
Dividends Paid to Noncontrolling Interest(68.5)(68.5)
Net Income  178.9 26.6 205.5 
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2025 $4,934.0 $1,733.9 $1,045.1 $7,713.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
62

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
  September 30, December 31,
  2025 2024
CURRENT ASSETS    
Advances to Affiliates $67.6 $30.4 
Accounts Receivable: 
Customers 42.5 58.9 
Affiliated Companies 154.7 134.1 
Miscellaneous— 1.3 
Total Accounts Receivable 197.2 194.3 
Prepayments and Other Current Assets 5.1 11.1 
TOTAL CURRENT ASSETS 269.9 235.8 
 
TRANSMISSION PROPERTY   
Transmission Property 15,925.1 14,913.4 
Other Property, Plant and Equipment 545.8 516.1 
Construction Work in Progress 2,097.6 1,965.4 
Total Transmission Property 18,568.5 17,394.9 
Accumulated Depreciation and Amortization 1,839.8 1,578.4 
TOTAL TRANSMISSION PROPERTY – NET 16,728.7 15,816.5 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 64.1 0.4 
Deferred Property Taxes 95.5 308.9 
Deferred Charges and Other Noncurrent Assets 50.4 8.7 
TOTAL OTHER NONCURRENT ASSETS 210.0 318.0 
 
TOTAL ASSETS $17,208.6 $16,370.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
63

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
September 30, 2025 and December 31, 2024
(Unaudited)
  September 30, December 31,
  2025 2024
(in millions)
CURRENT LIABILITIES    
Advances from Affiliates $108.9 $84.7 
Accounts Payable:  
General 354.1 360.5 
Affiliated Companies 108.9 117.0 
Long-term Debt Due Within One Year – Nonaffiliated— 90.0 
Accrued Taxes 401.1 665.9 
Accrued Interest 74.1 44.9 
Obligations Under Operating Leases1.3 1.3 
Other Current Liabilities 28.6 44.5 
TOTAL CURRENT LIABILITIES 1,077.0 1,408.8 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated 6,240.4 5,678.1 
Deferred Income Taxes 1,480.4 1,278.6 
Regulatory Liabilities 675.6 878.4 
Obligations Under Operating Leases1.7 1.2 
Deferred Credits and Other Noncurrent Liabilities 20.5 174.3 
TOTAL NONCURRENT LIABILITIES 8,418.6 8,010.6 
 
TOTAL LIABILITIES 9,495.6 9,419.4 
 
Rate Matters (Note 4) 
Commitments and Contingencies (Note 5) 
 
MEMBER’S EQUITY   
Paid-in Capital4,934.0 3,100.6 
Retained Earnings 1,733.9 3,850.3 
TOTAL MEMBER’S EQUITY 6,667.9 6,950.9 
Noncontrolling Interest1,045.1 — 
TOTAL EQUITY7,713.0 6,950.9 
 
TOTAL LIABILITIES AND EQUITY $17,208.6 $16,370.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
64

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  20252024
OPERATING ACTIVITIES 
Net Income $1,033.5 $548.2 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and Amortization 354.3 320.8 
Deferred Income Taxes (145.4)75.7 
Allowance for Equity Funds Used During Construction (64.7)(64.7)
Property Taxes 213.4 196.3 
Change in Other Noncurrent Assets (61.1)0.8 
Change in Other Noncurrent Liabilities (151.3)(40.1)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (2.9)5.4 
Accounts Payable 17.9 (16.1)
Accrued Taxes, Net (264.8)(149.9)
Other Current Assets 5.5 (1.9)
Other Current Liabilities 3.4 22.2 
Net Cash Flows from Operating Activities 937.8 896.7 
 
INVESTING ACTIVITIES   
Construction Expenditures (1,144.7)(1,042.9)
Change in Advances to Affiliates, Net (37.2)(114.7)
Other Investing Activities 21.3 13.6 
Net Cash Flows Used for Investing Activities (1,160.6)(1,144.0)
 
FINANCING ACTIVITIES  
Capital Contribution from AEP Member 42.9 34.6 
Capital Contribution from Noncontrolling Interest33.9 — 
Return of Capital to AEP Member— (4.5)
Issuance of Long-term Debt – Nonaffiliated560.0 445.7 
Retirement of Long-term Debt – Nonaffiliated(90.0)— 
Change in Advances from Affiliates, Net 24.2 (131.5)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs2,782.9 — 
Dividends Paid to AEP Member(3,062.6)(97.0)
Dividends Paid to Noncontrolling Interest(68.5)— 
Net Cash Flows from Financing Activities 222.8 247.3 
 
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 $139.8 $128.0 
Net Cash Paid for Income Taxes 115.4 5.7 
Construction Expenditures Included in Current Liabilities as of September 30, 222.5 221.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
65

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2025202420252024
 (in millions of KWhs)
Retail:    
Residential2,516 2,568 8,202 7,918 
Commercial1,530 1,553 4,495 4,482 
Industrial2,117 2,141 6,397 6,446 
Miscellaneous202 203 621 617 
Total Retail6,365 6,465 19,715 19,463 
Wholesale (a)966 550 2,269 1,768 
Total KWhs7,331 7,015 21,984 21,231 
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.


Summary of Heating and Cooling Degree Days
 Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2025202420252024
 (in degree days)
Actual – Heating— — 1,433 1,029 
Normal – Heating1 2 1,360 1,397 
Actual – Cooling748 962 1,176 1,499 
Normal – Cooling818 837 1,211 1,221 

66

Appalachian Power Company and Subsidiaries
Reconciliation of 2024 to 2025 Net Income
(in millions)
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2024 Net Income$109.8 $304.6 
  
Changes in Revenues: 
Retail Revenues13.4 111.5 
Off-system Sales2.9 4.1 
Transmission Revenues5.6 21.2 
Other Revenues5.2 7.6 
Total Change in Revenues27.1 144.4 
  
Changes in Expenses and Other: 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation(15.7)(12.1)
Other Operation and Maintenance(20.9)(33.1)
Depreciation and Amortization(2.8)(41.1)
Taxes Other Than Income Taxes(1.4)7.5 
Interest Income(1.3)(0.6)
Allowance for Equity Funds Used During Construction— 1.4 
Non-Service Cost Components of Net Periodic Benefit Cost(1.7)(4.7)
Interest Expense(2.8)(4.2)
Total Change in Expenses and Other(46.6)(86.9)
  
Income Tax Expense(9.2)(9.5)
  
2025 Net Income$81.1 $352.6 

Third Quarter of 2025 Compared to Third Quarter of 2024

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

•Retail Revenues increased $13 million primarily due to the following:
•A $23 million increase in fuel revenues.
•An $18 million increase in weather-normalized margins primarily in the residential class.
These increases were partially offset by:
•A $17 million decrease in weather-related usage primarily due to a 22% decrease in cooling degree days.
•A $10 million decrease in rider revenues.
•Transmission Revenues increased $6 million primarily due to continued transmission investment.
•Other Revenues increased $5 million primarily due to an increase in sales of renewable energy credits.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $16 million primarily due to an increase in West Virginia ENEC rates and renewable energy credit revenue.
•Other Operation and Maintenance expenses increased $21 million primarily due to the following:
•A $15 million increase in distribution expenses primarily due to an increase in storm-related and vegetation management expenses.
•A $4 million increase due to recoverable energy assistance program expenses for qualified Virginia customers.
•Income Tax Expense increased $9 million primarily due to an increase in flow-through cost of removal.


67

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

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

•Retail Revenues increased $112 million primarily due to the following:
•A $58 million increase in fuel revenues.
•A $21 million increase in rider revenues.
•A $19 million increase in weather-normalized margins primarily in the residential class.
•A $16 million increase in weather-related usage primarily due to a 39% increase in heating degree days, partially offset by a 22% decrease in cooling degree days.
•Transmission Revenues increased $21 million primarily due to the following:
•A $15 million increase due to continued transmission investment.
•A $6 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•Other Revenues increased $8 million primarily due to an increase in sales of renewable energy credits.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $12 million primarily due to the following:
•A $47 million increase in purchased power prices, West Virginia ENEC rates and renewable energy credit revenue.
This increase was partially offset by:
•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.
•Other Operation and Maintenance expenses increased $33 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 $5 million increase in recoverable PJM expenses.
•A $5 million increase in vegetation management expenses.
•An $18 million increase due to recoverable energy assistance program expenses for qualified Virginia customers.
•A $13 million increase in distribution expenses primarily due to an increase in storm-related expenses.
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 $41 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes decreased $8 million primarily due to lower business and occupation taxes.
•Income Tax Expense increased $10 million primarily due to the following:
•A $13 million increase due to a decrease in amortization of Excess ADIT.
•A $12 million increase due to an increase in pretax book income.
•A $7 million increase due to an increase in flow-through CAMT expense.
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.






68


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2025202420252024
REVENUES    
Electric Generation, Transmission and Distribution$981.7 $960.6 $2,955.4 $2,836.6 
Sales to AEP Affiliates70.3 65.2 208.5 183.1 
Other Revenues4.0 3.1 12.6 12.4 
TOTAL REVENUES1,056.0 1,028.9 3,176.5 3,032.1 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation374.1 358.4 1,072.1 1,060.0 
Other Operation206.4 204.2 639.4 628.8 
Maintenance105.1 86.4 267.2 244.7 
Depreciation and Amortization151.8 149.0 485.6 444.5 
Taxes Other Than Income Taxes45.7 44.3 125.0 132.5 
TOTAL EXPENSES883.1 842.3 2,589.3 2,510.5 
OPERATING INCOME172.9 186.6 587.2 521.6 
Other Income (Expense):    
Interest Income0.5 1.8 3.2 3.8 
Allowance for Equity Funds Used During Construction4.2 4.2 12.8 11.4 
Non-Service Cost Components of Net Periodic Benefit Cost5.2 6.9 15.7 20.4 
Interest Expense(70.0)(67.2)(207.6)(203.4)
INCOME BEFORE INCOME TAX EXPENSE112.8 132.3 411.3 353.8 
Income Tax Expense31.7 22.5 58.7 49.2 
NET INCOME $81.1 $109.8 $352.6 $304.6 
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
69

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
2025202420252024
Net Income$81.1 $109.8 $352.6 $304.6 
OTHER COMPREHENSIVE LOSS, NET OF TAXES  
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2025 and 2024, Respectively, and $(0.2) and $(0.2) for the Nine Months Ended September 30, 2025 and 2024, Respectively
(0.2)(0.2)(0.6)(0.6)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $(0.1) for the Three Months Ended September 30, 2025 and 2024, Respectively, and $(0.1) and $(0.2) for the Nine Months Ended September 30, 2025 and 2024, Respectively
(0.1)(0.2)(0.3)(0.8)
TOTAL OTHER COMPREHENSIVE LOSS(0.3)(0.4)(0.9)(1.4)
TOTAL COMPREHENSIVE INCOME$80.8 $109.4 $351.7 $303.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
70

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 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 Parent100.0100.0 
Net Income136.5 136.5 
Other Comprehensive Loss(0.5)(0.5)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2024260.4 1,934.5 3,322.0 (4.2)5,512.7 
Capital Contribution from Parent9.5 9.5 
Net Income  58.3  58.3 
Other Comprehensive Loss   (0.5)(0.5)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2024260.4 1,944.0 3,380.3 (4.7)5,580.0 
Return of Capital to Parent(4.5)(4.5)
Common Stock Dividends(75.0)(75.0)
Net Income109.8 109.8 
Other Comprehensive Loss(0.4)(0.4)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2024
$260.4 $1,939.5 $3,415.1 $(5.1)$5,609.9 
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 Income164.6 164.6 
Other Comprehensive Loss(0.3)(0.3)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2025260.4 1,944.1 3,646.8 11.0 5,862.3 
Capital Contribution from Parent7.27.2 
Net Income106.9 106.9 
Other Comprehensive Loss(0.3)(0.3)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2025260.4 1,951.3 3,753.7 10.7 5,976.1 
Capital Contribution from Parent1.3 1.3 
Net Income81.1 81.1 
Other Comprehensive Loss(0.3)(0.3)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2025$260.4 $1,952.6 $3,834.8 $10.4 $6,058.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

71

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
September 30,December 31,
20252024
CURRENT ASSETS  
Cash and Cash Equivalents$3.9 $3.9 
Restricted Cash for Securitized Funding10.8 16.2 
Advances to Affiliates49.6 17.7 
Accounts Receivable:  
Customers194.5 185.7 
Affiliated Companies120.4 110.5 
Accrued Unbilled Revenues45.5 93.1 
Miscellaneous0.3 0.3 
Allowance for Credit Losses(2.1)(2.0)
Total Accounts Receivable358.6 387.6 
Fuel268.1 308.0 
Materials and Supplies134.8 131.7 
Risk Management Assets92.0 35.7 
Regulatory Asset for Under-Recovered Fuel Costs79.3 148.1 
Prepayments and Other Current Assets37.9 46.0 
TOTAL CURRENT ASSETS1,035.0 1,094.9 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation7,282.2 7,272.6 
Transmission5,140.2 5,001.5 
Distribution5,827.3 5,568.5 
Other Property, Plant and Equipment1,141.4 1,062.9 
Construction Work in Progress845.1 742.6 
Total Property, Plant and Equipment20,236.2 19,648.1 
Accumulated Depreciation and Amortization6,297.0 6,035.6 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET13,939.2 13,612.5 
OTHER NONCURRENT ASSETS  
Regulatory Assets1,498.9 1,366.0 
Securitized Assets85.1 106.2 
Employee Benefits and Pension Assets215.5 203.9 
Operating Lease Assets68.0 67.0 
Deferred Charges and Other Noncurrent Assets151.4 215.4 
TOTAL OTHER NONCURRENT ASSETS2,018.9 1,958.5 
TOTAL ASSETS$16,993.1 $16,665.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
72

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2025 and December 31, 2024
(Unaudited)
 September 30,December 31,
 20252024
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$— $95.0 
Accounts Payable:  
General418.6 427.2 
Affiliated Companies213.2 205.9 
Long-term Debt Due Within One Year – Nonaffiliated206.2 798.6 
Customer Deposits95.4 86.6 
Accrued Taxes96.9 168.8 
Accrued Interest91.6 63.7 
Obligations Under Operating Leases16.0 13.7 
Other Current Liabilities140.4 166.0 
TOTAL CURRENT LIABILITIES1,278.3 2,025.5 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated5,551.9 4,861.7 
Deferred Income Taxes2,115.5 2,033.5 
Regulatory Liabilities and Deferred Investment Tax Credits1,084.6 1,115.8 
Asset Retirement Obligations789.8 767.4 
Employee Benefits and Pension Obligations27.8 29.6 
Obligations Under Operating Leases52.6 54.0 
Deferred Credits and Other Noncurrent Liabilities34.4 30.4 
TOTAL NONCURRENT LIABILITIES9,656.6 8,892.4 
TOTAL LIABILITIES10,934.9 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 Capital1,952.6 1,944.1 
Retained Earnings3,834.8 3,532.2 
Accumulated Other Comprehensive Income (Loss)10.4 11.3 
TOTAL COMMON SHAREHOLDER’S EQUITY6,058.2 5,748.0 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$16,993.1 $16,665.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
73

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20252024
OPERATING ACTIVITIES  
Net Income$352.6 $304.6 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization485.6 444.5 
Deferred Income Taxes24.7 (23.0)
Allowance for Equity Funds Used During Construction(12.8)(11.4)
Mark-to-Market of Risk Management Contracts(56.5)(33.6)
Deferred Fuel Over/Under-Recovery, Net68.2 124.1 
Change in Regulatory Assets(153.4)(16.1)
Change in Other Noncurrent Assets32.5 3.0 
Change in Other Noncurrent Liabilities25.4 5.6 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net29.0 3.6 
Fuel, Materials and Supplies36.8 62.2 
Accounts Payable29.2 50.4 
Accrued Taxes, Net(80.1)12.8 
Other Current Assets15.5 (24.7)
Other Current Liabilities11.9 34.8 
Net Cash Flows from Operating Activities808.6 936.8 
INVESTING ACTIVITIES  
Construction Expenditures(748.5)(708.7)
Change in Advances to Affiliates, Net(31.9)— 
Other Investing Activities12.8 14.4 
Net Cash Flows Used for Investing Activities(767.6)(694.3)
FINANCING ACTIVITIES  
Capital Contribution from Parent8.5 109.5 
Return of Capital to Parent— (4.5)
Issuance of Long-term Debt – Nonaffiliated593.2 480.8 
Change in Advances from Affiliates, Net(95.0)(338.7)
Retirement of Long-term Debt – Nonaffiliated(498.3)(413.5)
Principal Payments for Finance Lease Obligations(6.4)(6.5)
Dividends Paid on Common Stock(50.0)(75.0)
Other Financing Activities1.6 0.3 
Net Cash Flows Used for Financing Activities(46.4)(247.6)
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding(5.4)(5.1)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period20.1 19.9 
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period$14.7 $14.8 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$172.4 $159.6 
Net Cash Paid for Income Taxes76.4 27.4 
Cash Paid (Received) for Transferable Tax Credits— (0.2)
Noncash Acquisitions Under Finance Leases2.5 0.9 
Construction Expenditures Included in Current Liabilities as of September 30,128.6 129.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
74

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months Ended 
September 30,		Nine Months Ended 
September 30,
 2025202420252024
 (in millions of KWhs)
Retail:    
Residential1,568 1,552 4,218 4,152 
Commercial1,866 1,450 4,552 4,015 
Industrial1,825 1,901 5,429 5,562 
Miscellaneous10 10 32 35 
Total Retail5,269 4,913 14,231 13,764 
Wholesale (a)1,423 1,305 5,366 4,042 
Total KWhs6,692 6,218 19,597 17,806 
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.


Summary of Heating and Cooling Degree Days
 Three Months Ended 
September 30,		Nine Months Ended 
September 30,
 2025202420252024
 (in degree days)
Actual – Heating— — 2,335 1,826 
Normal – Heating6 6 2,371 2,428 
Actual – Cooling622 608 902 965 
Normal – Cooling582 583 867 852 
75

Indiana Michigan Power Company and Subsidiaries
Reconciliation of 2024 to 2025 Net Income
(in millions)
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2024 Net Income$179.1 $359.3 
  
Changes in Revenues: 
Retail Revenues49.8 174.3 
Off-system Sales26.4 89.1 
Transmission Revenues2.2 12.9 
Other Revenues0.3 0.1 
Total Change in Revenues78.7 276.4 
  
Changes in Expenses and Other: 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation(39.6)(139.1)
Purchased Electricity from AEP Affiliates(8.9)(45.3)
Other Operation and Maintenance(21.5)(33.7)
Asset Impairments and Other Related Charges— 13.4 
Depreciation and Amortization(1.1)(27.2)
Taxes Other Than Income Taxes(2.0)(1.9)
Other Income2.3 4.3 
Non-Service Cost Components of Net Periodic Benefit Cost(2.0)(4.8)
Interest Expense(2.3)(12.8)
Total Change in Expenses and Other(75.1)(247.1)
  
Income Tax Benefit(33.0)(57.3)
  
2025 Net Income$149.7 $331.3 

Third Quarter of 2025 Compared to Third Quarter of 2024

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

•Retail Revenues increased $50 million primarily due to the following:
•A $46 million increase in rider revenues.
•A $19 million increase in fuel revenues.
•A $9 million increase due to the implementation of new base rates in Indiana and Michigan.
•An $8 million increase in weather-normalized margins primarily in the commercial class.
These increases were partially offset by:
•A $39 million decrease due to regulatory provisions for refund.
•Off-system Sales increased $26 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $40 million primarily due to an increase in recoverable fuel and purchased power costs and a prior year regulatory true-up associated with a final commission order, partially offset by a decrease in Rockport Plant, Unit 2 merchant generation fuel costs.
•Purchased Electricity from AEP Affiliates increased $9 million primarily due to an increase in purchased electricity from AEGCo.
•Other Operation and Maintenance expenses increased $22 million primarily due to the following:
•A $10 million increase in distribution expenses primarily due to an increase in vegetation management costs and other distribution-related expenses.
•A $7 million increase in nuclear expenses at Cook Plant.
•Income Tax Benefit decreased $33 million primarily due to the timing of the recognition of PTCs.
76

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

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

•Retail Revenues increased $174 million primarily due to the following:
•An $87 million increase due to the implementation of new base rates in Indiana and Michigan.
•An $80 million increase in fuel revenues.
•A $62 million increase in rider revenues.
•A $43 million increase in weather-normalized margins primarily in the commercial class, partially offset by a decrease in the industrial class.
•A $9 million increase in weather-related usage primarily due to a 28% increase in heating degree days.
These increases were partially offset by:
•A $110 million decrease due to regulatory provisions for refund.
•Off-system Sales increased $89 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales.
•Transmission Revenues increased $13 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $139 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 $45 million primarily due to an increase in purchased electricity from AEGCo.
•Other Operation and Maintenance expenses increased $34 million primarily due to the following:
•A $38 million increase in distribution expenses primarily due to an increase in vegetation management costs and other distribution-related expenses.
•A $12 million increase in nuclear expenses at Cook Plant.
•A $10 million increase in transmission expenses primarily due to a $17 million increase in recoverable PJM expenses, partially offset by a $6 million decrease due to the June 2025 FERC order related to the treatment of stand-alone NOLCs in transmission formula rates.
These increases were partially offset by:
•A $13 million decrease in demand side management expenses.
•An $11 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 non-utility operation expenses due to a decrease in River Transportation Division barging 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 $27 million primarily due to the following:
•A $16 million increase due to a prior year deferral combined with current year amortization of Excess ADIT as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.
•A $12 million increase due to a higher depreciable base.
•Interest Expense increased $13 million primarily due to a prior year deferral combined with current year amortization of Excess ADIT as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.
•Income Tax Benefit decreased $57 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 $20 million decrease in amortization of Excess ADIT.
•A $6 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 stand-alone NOLCs in transmission formula rates.

77


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2025202420252024
REVENUES    
Electric Generation, Transmission and Distribution$841.2 $727.2 $2,335.9 $1,959.5 
Sales to AEP Affiliates3.9 2.2 9.3 9.9 
(Provision for)/Reversal of – Revenue Refund – Affiliated— (0.9)8.5 (4.7)
Provision for Refund – Nonaffiliated(51.0)(12.3)(134.9)(27.2)
Other Revenues – Affiliated16.9 15.2 46.8 50.7 
Other Revenues – Nonaffiliated1.2 2.1 6.0 7.0 
TOTAL REVENUES812.2 733.5 2,271.6 1,995.2 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation157.8 118.2 466.0 326.9 
Purchased Electricity from AEP Affiliates71.9 63.0 214.3 169.0 
Other Operation188.8 180.0 537.2 548.5 
Maintenance70.8 58.1 218.7 173.7 
Asset Impairments and Other Related Charges— — — 13.4 
Depreciation and Amortization133.7 132.6 386.4 359.2 
Taxes Other Than Income Taxes23.0 21.0 70.8 68.9 
TOTAL EXPENSES646.0 572.9 1,893.4 1,659.6 
OPERATING INCOME 166.2 160.6 378.2 335.6 
Other Income (Expense):    
Other Income5.6 3.3 14.0 9.7 
Non-Service Cost Components of Net Periodic Benefit Cost4.8 6.8 15.2 20.0 
Interest Expense(38.0)(35.7)(111.7)(98.9)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)138.6 135.0 295.7 266.4 
Income Tax Expense (Benefit)(11.1)(44.1)(35.6)(92.9)
NET INCOME $149.7 $179.1 $331.3 $359.3 
The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
78

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended
 September 30,September 30,
2025202420252024
Net Income$149.7 $179.1 $331.3 $359.3 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES   
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2025 and 2024, Respectively, and $0.1 and $0.1 for the Nine Months Ended September 30, 2025 and 2024, Respectively
0.2 0.1 0.4 0.3 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2025 and 2024, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2025 and 2024, Respectively
— — 0.1 (0.1)
TOTAL OTHER COMPREHENSIVE INCOME0.2 0.1 0.5 0.2 
TOTAL COMPREHENSIVE INCOME$149.9 $179.2 $331.8 $359.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
79

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 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, 202456.6 997.6 2,194.1 (0.5)3,247.8 
Capital Contribution from Parent5.0 5.0 
Common Stock Dividends(37.5)(37.5)
Net Income35.2 35.2 
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 202456.6 1,002.6 2,191.8 (0.5)3,250.5 
Return of Capital to Parent(1.8)(1.8)
Common Stock Dividends(37.5)(37.5)
Net Income179.1 179.1 
Other Comprehensive Income0.1 0.1 
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2024$56.6 $1,000.8 $2,333.4 $(0.4)$3,390.4 
     
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 Income57.5 57.5 
Other Comprehensive Income0.1 0.1 
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 202556.6 1,011.7 2,335.5 0.3 3,404.1 
Capital Contribution from Parent7.4 7.4 
Net Income  124.1  124.1 
Other Comprehensive Income   0.2 0.2 
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 202556.6 1,019.1 2,459.6 0.5 3,535.8 
Capital Contribution from Parent1.3 1.3 
Net Income149.7 149.7 
Other Comprehensive Income0.2 0.2 
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2025$56.6 $1,020.4 $2,609.3 $0.7 $3,687.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
80

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
September 30,December 31,
 20252024
CURRENT ASSETS  
Cash and Cash Equivalents$1.8 $1.5 
Advances to Affiliates157.2 — 
Accounts Receivable:  
Customers67.6 58.7 
Affiliated Companies84.6 79.1 
Accrued Unbilled Revenues14.1 21.4 
Miscellaneous0.6 6.3 
Total Accounts Receivable166.9 165.5 
Fuel47.9 83.4 
Materials and Supplies208.8 212.2 
Risk Management Assets10.9 18.4 
Regulatory Asset for Under-Recovered Fuel Costs— 10.6 
Prepayments and Other Current Assets53.0 52.0 
TOTAL CURRENT ASSETS646.5 543.6 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation5,466.5 5,503.0 
Transmission2,010.4 1,957.8 
Distribution3,752.5 3,535.0 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)1,035.8 992.4 
Construction Work in Progress416.9 334.9 
Total Property, Plant and Equipment12,682.1 12,323.1 
Accumulated Depreciation, Depletion and Amortization4,839.0 4,643.8 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET7,843.1 7,679.3 
OTHER NONCURRENT ASSETS  
Regulatory Assets620.4 548.1 
Spent Nuclear Fuel and Decommissioning Trusts4,858.9 4,395.1 
Operating Lease Assets56.1 51.5 
Deferred Charges and Other Noncurrent Assets286.9 317.9 
TOTAL OTHER NONCURRENT ASSETS5,822.3 5,312.6 
TOTAL ASSETS$14,311.9 $13,535.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
81

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2025 and December 31, 2024
(dollars in millions)
(Unaudited)
 September 30,December 31,
 20252024
CURRENT LIABILITIES  
Advances from Affiliates$— $126.8 
Accounts Payable:  
General211.2 202.2 
Affiliated Companies144.0 98.5 
Long-term Debt Due Within One Year – Nonaffiliated
   (September 30, 2025 and December 31, 2024 Amounts Include $86.3 and $79.0,
   Respectively, Related to DCC Fuel)
86.3 269.2 
Customer Deposits54.7 59.1 
Accrued Taxes82.9 102.2 
Accrued Interest38.7 41.3 
Obligations Under Operating Leases16.4 12.3 
Regulatory Liability for Over-Recovered Fuel Costs21.1 10.3 
Other Current Liabilities200.3 149.3 
TOTAL CURRENT LIABILITIES855.6 1,071.2 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated3,398.8 3,225.1 
Deferred Income Taxes1,179.7 1,175.8 
Regulatory Liabilities and Deferred Investment Tax Credits2,893.1 2,480.8 
Asset Retirement Obligations2,156.3 2,088.8 
Obligations Under Operating Leases40.6 40.1 
Deferred Credits and Other Noncurrent Liabilities100.8 57.2 
TOTAL NONCURRENT LIABILITIES9,769.3 9,067.8 
TOTAL LIABILITIES10,624.9 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 Capital1,020.4 1,011.7 
Retained Earnings2,609.3 2,328.0 
Accumulated Other Comprehensive Income (Loss)0.7 0.2 
TOTAL COMMON SHAREHOLDER’S EQUITY3,687.0 3,396.5 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$14,311.9 $13,535.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
82

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20252024
OPERATING ACTIVITIES  
Net Income$331.3 $359.3 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and Amortization386.4 359.2 
Deferred Income Taxes(51.9)(70.7)
Deferral of Incremental Nuclear Refueling Outage Expenses, Net(40.0)(3.2)
Asset Impairments and Other Related Charges— 13.4 
Allowance for Equity Funds Used During Construction(13.1)(10.1)
Mark-to-Market of Risk Management Contracts7.8 16.3 
Amortization of Nuclear Fuel80.9 74.3 
Deferred Fuel Over/Under-Recovery, Net21.4 (13.7)
Change in Other Noncurrent Assets(19.6)24.4 
Change in Other Noncurrent Liabilities111.8 49.5 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(1.4)(8.1)
Fuel, Materials and Supplies38.9 13.8 
Accounts Payable78.5 (57.7)
Accrued Taxes, Net(19.3)(56.1)
Other Current Assets9.8 (2.0)
Other Current Liabilities19.4 (10.2)
Net Cash Flows from Operating Activities940.9 678.4 
INVESTING ACTIVITIES  
Construction Expenditures(478.3)(434.7)
Change in Advances to Affiliates, Net(157.2)— 
Purchases of Investment Securities(2,386.5)(2,389.0)
Sales of Investment Securities2,332.2 2,336.0 
Acquisitions of Nuclear Fuel(88.9)(98.4)
Other Investing Activities31.2 5.7 
Net Cash Flows Used for Investing Activities(747.5)(580.4)
FINANCING ACTIVITIES  
Capital Contribution from Parent8.7 5.0 
Return of Capital to Parent— (1.8)
Issuance of Long-term Debt – Nonaffiliated249.0 80.4 
Change in Advances from Affiliates, Net(126.8)13.7 
Retirement of Long-term Debt – Nonaffiliated(269.9)(76.1)
Principal Payments for Finance Lease Obligations(4.8)(5.2)
Dividends Paid on Common Stock(50.0)(112.5)
Other Financing Activities0.7 0.5 
Net Cash Flows Used for Financing Activities(193.1)(96.0)
Net Increase in Cash and Cash Equivalents0.3 2.0 
Cash and Cash Equivalents at Beginning of Period1.5 2.1 
Cash and Cash Equivalents at End of Period$1.8 $4.1 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$111.1 $111.5 
Net Cash Paid (Received) for Income Taxes0.9 (4.4)
Noncash Acquisitions Under Finance Leases1.7 1.1 
Construction Expenditures Included in Current Liabilities as of September 30,74.9 69.6 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,1.4 8.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
83

OHIO POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2025202420252024
 (in millions of KWhs)
Retail:    
Residential4,121 4,090 11,240 10,905 
Commercial7,391 5,388 19,203 15,138 
Industrial3,520 3,544 10,654 10,585 
Miscellaneous23 24 76 77 
Total Retail (a)15,055 13,046 41,173 36,705 
Wholesale (b)552 504 1,683 1,347 
Total KWhs15,607 13,550 42,856 38,052 

(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.


Summary of Heating and Cooling Degree Days
 Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2025202420252024
 (in degree days)
Actual – Heating— — 2,077 1,573 
Normal – Heating3 4 1,996 2,056 
Actual – Cooling734 844 1,076 1,266 
Normal – Cooling707 699 1,032 1,008 
84

Ohio Power Company and Subsidiaries
Reconciliation of 2024 to 2025 Net Income
(in millions)
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2024 Net Income $112.7 $201.7 
 
Changes in Revenues: 
Retail Revenues40.5 23.1 
Off-system Sales16.1 41.9 
Transmission Revenues4.5 10.7 
Other Revenues4.9 (7.3)
Total Change in Revenues66.0 68.4 
  
Changes in Expenses and Other: 
Purchased Electricity for Resale(46.3)(38.4)
Purchased Electricity from AEP Affiliates(4.3)37.1 
Other Operation and Maintenance(2.9)(30.1)
Asset Impairments and Other Related Charges— 52.9 
Depreciation and Amortization(10.5)8.6 
Taxes Other Than Income Taxes(7.6)1.5 
Other Income(0.9)(0.9)
Allowance for Equity Funds Used During Construction(1.2)3.1 
Non-Service Cost Components of Net Periodic Benefit Cost(1.2)(3.4)
Interest Expense(0.9)(7.7)
Total Change in Expenses and Other(75.8)22.7 
  
Income Tax Expense(2.1)(28.4)
Equity Earnings of Unconsolidated Subsidiaries0.1 2.3 
  
2025 Net Income$100.9 $266.7 

Third Quarter of 2025 Compared to Third Quarter of 2024

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

•Retail Revenues increased $41 million primarily due to the following:
•A $49 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.
•A $9 million increase in weather-normalized revenues primarily in the residential class.
These increases were partially offset by:
•A $12 million decrease in rider revenues.
•A $9 million decrease in weather-related usage driven by a 13% decrease in cooling degree days.
•Off-system Sales increased $16 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.
•Other Revenues increased $5 million primarily due to data center load study revenues.


85

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

•Purchased Electricity for Resale expenses increased $46 million primarily due to the following:
•A $39 million increase in recoverable auction purchases primarily due to higher prices.
•A $6 million increase in recoverable alternative energy rider expenses.
•Depreciation and Amortization expenses increased $11 million primarily due to higher depreciable base and lower capital rider under-recoveries.
•Taxes Other Than Income Taxes increased $8 million primarily due to an increase in property taxes.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

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

•Retail Revenues increased $23 million primarily due to the following:
•A $45 million increase in rider revenues.
•A $13 million increase in weather-related usage driven by a 32% increase in heating degree days.
•A $5 million increase in weather-normalized revenues primarily in the commercial class.
These increases were partially offset by:
•A $39 million decrease due to lower purchased power to serve OPCo’s SSO customers.
•Off-system Sales increased $42 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.
•Transmission Revenues increased $11 million primarily due to continued transmission investment.
•Other Revenues decreased $7 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 for Resale expenses increased $38 million primarily due to the following:
•A $24 million increase primarily due to the amortization of OVEC-related purchased power regulatory assets driven by higher market prices.
•A $24 million increase due to a reduction in regulatory assets for OVEC-related purchased power costs that are no longer probable of future recovery due to approved legislation in Ohio in 2025.
These increases were partially offset by:
•A $6 million decrease in recoverable alternative energy rider expenses.
•Purchased Electricity from AEP Affiliates expenses decreased $37 million primarily due to decreased recoverable purchases to serve SSO customers.
•Other Operation and Maintenance expenses increased $30 million primarily due to the following:
•A $63 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
This increase was partially offset by:
•A $20 million decrease related to recoverable energy assistance program expenses for qualified Ohio customers.
•An $11 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 $9 million primarily due to capital rider under-recoveries.
•Interest Expense increased $8 million primarily due to higher debt balances.
•Income Tax Expense increased $28 million primarily due to the following:
•A $19 million increase due to an increase in pretax book income.
•A $10 million increase due to a decrease in amortization of Excess ADIT.
86


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
September 30,September 30,
 2025202420252024
REVENUES    
Electricity, Transmission and Distribution$1,058.9 $995.8 $2,959.2 $2,899.0 
Sales to AEP Affiliates7.7 5.6 23.7 17.0 
Other Revenues3.6 2.8 9.8 8.3 
TOTAL REVENUES1,070.2 1,004.2 2,992.7 2,924.3 
EXPENSES    
Purchased Electricity for Resale245.4 199.1 681.2 642.8 
Purchased Electricity from AEP Affiliates18.4 14.1 49.1 86.2 
Other Operation340.6 343.2 957.6 920.2 
Maintenance71.8 66.3 187.4 194.7 
Asset Impairments and Other Related Charges— — — 52.9 
Depreciation and Amortization96.6 86.1 285.3 293.9 
Taxes Other Than Income Taxes144.5 136.9 423.5 425.0 
TOTAL EXPENSES917.3 845.7 2,584.1 2,615.7 
OPERATING INCOME152.9 158.5 408.6 308.6 
Other Income (Expense):    
Other Income— 0.9 0.9 1.8 
Allowance for Equity Funds Used During Construction5.2 6.4 19.3 16.2 
Non-Service Cost Components of Net Periodic Benefit Cost4.2 5.4 12.8 16.2 
Interest Expense(39.6)(38.7)(117.6)(109.9)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS (LOSS)122.7 132.5 324.0 232.9 
Income Tax Expense21.9 19.8 58.8 30.4 
Equity Earnings (Loss) of Unconsolidated Subsidiaries0.1 — 1.5 (0.8)
NET INCOME$100.9 $112.7 $266.7 $201.7 
The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
87

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 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 Income70.6 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 
Capital Contribution from Parent0.8 0.8 
Net Income112.7 112.7 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2024
$321.2 $1,013.6 $2,439.0 $3,773.8 
    
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 Income63.0 63.0 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2025
321.2 1,020.0 2,559.9 3,901.1 
Capital Contribution from Parent1.8 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 
Net Income100.9 100.9 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2025
$321.2 $1,021.8 $2,738.6 $4,081.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
88

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
 September 30,December 31,
 20252024
CURRENT ASSETS  
Cash and Cash Equivalents$5.4 $4.5 
Advances to Affiliates— 114.9 
Accounts Receivable:  
Customers147.2 189.2 
Affiliated Companies125.4 117.5 
Accrued Unbilled Revenues25.2 31.1 
Miscellaneous0.2 8.6 
Total Accounts Receivable298.0 346.4 
Materials and Supplies168.8 141.4 
Prepayments and Other Current Assets18.7 19.9 
TOTAL CURRENT ASSETS490.9 627.1 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Transmission3,838.7 3,663.9 
Distribution7,510.7 7,244.0 
Other Property, Plant and Equipment1,265.7 1,256.0 
Construction Work in Progress783.1 691.1 
Total Property, Plant and Equipment13,398.2 12,855.0 
Accumulated Depreciation and Amortization2,974.1 2,883.9 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET10,424.1 9,971.1 
OTHER NONCURRENT ASSETS  
Regulatory Assets347.6 379.1 
Operating Lease Assets53.4 60.4 
Deferred Charges and Other Noncurrent Assets310.4 661.0 
TOTAL OTHER NONCURRENT ASSETS711.4 1,100.5 
TOTAL ASSETS$11,626.4 $11,698.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
89

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2025 and December 31, 2024
(Unaudited)
 September 30,December 31,
 20252024
(in millions)
CURRENT LIABILITIES  
Advances from Affiliates$13.0 $— 
Accounts Payable:  
General354.4 343.6 
Affiliated Companies286.6 204.9 
Risk Management Liabilities6.3 7.3 
Customer Deposits100.4 108.1 
Accrued Taxes421.3 836.1 
Obligations Under Operating Leases13.5 12.3 
Other Current Liabilities199.8 182.2 
TOTAL CURRENT LIABILITIES1,395.3 1,694.5 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated3,717.8 3,715.7 
Long-term Risk Management Liabilities38.0 40.2 
Deferred Income Taxes1,249.6 1,201.1 
Regulatory Liabilities and Deferred Investment Tax Credits904.9 987.7 
Obligations Under Operating Leases40.2 48.4 
Deferred Credits and Other Noncurrent Liabilities199.0 127.0 
TOTAL NONCURRENT LIABILITIES6,149.5 6,120.1 
TOTAL LIABILITIES7,544.8 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 Capital1,021.8 1,020.0 
Retained Earnings2,738.6 2,542.9 
TOTAL COMMON SHAREHOLDER’S EQUITY4,081.6 3,884.1 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$11,626.4 $11,698.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
90

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20252024
OPERATING ACTIVITIES  
Net Income$266.7 $201.7 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization285.3 293.9 
Deferred Income Taxes33.9 0.2 
Asset Impairments and Other Related Charges— 52.9 
Allowance for Equity Funds Used During Construction(19.3)(16.2)
Mark-to-Market of Risk Management Contracts(3.2)0.9 
Property Taxes306.4 286.6 
Change in Other Noncurrent Assets39.2 19.2 
Change in Other Noncurrent Liabilities(11.4)47.2 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net48.4 (39.8)
Materials and Supplies(10.2)33.8 
Accounts Payable131.3 (43.4)
Customer Deposits(7.7)6.1 
Accrued Taxes, Net(416.0)(322.3)
Other Current Assets2.5 (11.9)
Other Current Liabilities0.1 17.2 
Net Cash Flows from Operating Activities646.0 526.1 
INVESTING ACTIVITIES  
Construction Expenditures(747.1)(688.5)
Change in Advances to Affiliates, Net114.9 (97.4)
Other Investing Activities45.3 29.4 
Net Cash Flows Used for Investing Activities(586.9)(756.5)
FINANCING ACTIVITIES  
Capital Contribution from Parent1.8 0.8 
Issuance of Long-term Debt – Nonaffiliated— 346.3 
Change in Advances from Affiliates, Net13.0 (110.5)
Principal Payments for Finance Lease Obligations(3.4)(4.0)
Dividends Paid on Common Stock(71.0)— 
Other Financing Activities1.4 1.0 
Net Cash Flows from (Used for) Financing Activities(58.2)233.6 
Net Increase in Cash and Cash Equivalents0.9 3.2 
Cash and Cash Equivalents at Beginning of Period4.5 6.4 
Cash and Cash Equivalents at End of Period$5.4 $9.6 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$90.6 $82.8 
Net Cash Paid (Received) for Income Taxes53.1 (5.1)
Noncash Acquisitions Under Finance Leases1.5 1.1 
Construction Expenditures Included in Current Liabilities as of September 30,118.5 126.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
91

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2025202420252024
 (in millions of KWhs)
Retail:    
Residential2,027 2,170 4,938 5,084 
Commercial1,706 1,733 4,512 4,348 
Industrial1,567 1,524 4,427 4,436 
Miscellaneous360 371 964 981 
Total Retail5,660 5,798 14,841 14,849 
Wholesale (a)168 24 253 135 
Total KWhs5,828 5,822 15,094 14,984 
(a)Includes municipalities and cooperatives, unit power and other wholesale customers.


Summary of Heating and Cooling Degree Days
 Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2025202420252024
 (in degree days)
Actual – Heating— — 1,193 917 
Normal – Heating— — 1,081 1,088 
Actual – Cooling1,353 1,433 1,982 2,263 
Normal – Cooling1,425 1,429 2,154 2,111 
92

Public Service Company of Oklahoma
Reconciliation of 2024 to 2025 Net Income
(in millions)
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2024 Net Income$113.7 $222.0 
Changes in Revenues:
Retail Revenues (a)73.0 88.9 
Transmission Revenues(2.8)9.3 
Other Revenues7.8 (3.3)
Total Change in Revenues78.0 94.9 
Changes in Expenses and Other: 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation(9.4)18.2 
Other Operation and Maintenance(35.5)(48.7)
Depreciation and Amortization3.5 (0.6)
Taxes Other Than Income Taxes(2.0)0.8 
Interest Income(0.2)1.6 
Allowance for Equity Funds Used During Construction(0.2)2.7 
Non-Service Cost Components of Net Periodic Benefit Cost(0.8)(2.2)
Interest Expense(13.5)(29.4)
Total Change in Expenses and Other(58.1)(57.6)
  
Income Tax Benefit(3.8)(38.3)
  
2025 Net Income$129.8 $221.0 

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

Third Quarter of 2025 Compared to Third Quarter of 2024

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

•Retail Revenues increased $73 million primarily due to the following:
•An $81 million increase in base rate and rider revenues.
•A $7 million increase in weather-normalized margins primarily in the residential class partially offset by a decrease in the industrial class.
These increases were partially offset by:
•A $10 million decrease in fuel revenue primarily due to lower authorized fuel rates.
•An $8 million decrease in weather-related usage primarily driven by a 6% decrease in cooling degree days.
•Other Revenues increased $8 million primarily due to an increase in sales of renewable energy credits.

Expenses and Other changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $9 million primarily due to higher current amortization of under-recovered deferred fuel regulatory assets as the result of increased recoverable PTCs.
•Other Operation and Maintenance expenses increased $36 million primarily due to the following:
•A $17 million increase in transmission expenses primarily due to increased transmission investments.
•A $10 million increase in generation expenses primarily due to acquisitions of generation facilities in 2025.
•Interest Expense increased $14 million primarily due to higher long-term debt balances.

93

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

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

•Retail Revenues increased $89 million primarily due to the following:
•A $145 million increase in base rate and rider revenues.
•An $18 million increase in weather-normalized margins primarily in the residential class partially offset by a decrease in the industrial class.
These increases were partially offset by:
•A $60 million decrease in fuel revenue primarily due to lower authorized fuel rates.
•A $20 million decrease in weather-related usage primarily driven by a 12% decrease in cooling degree days.
•Transmission Revenues increased $9 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates and continued transmission investment.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $18 million primarily due to lower current amortization of under-recovered deferred fuel regulatory assets as a result of lower authorized fuel rates and increased fuel and purchased power costs, offset by increased recoverable PTCs.
•Other Operation and Maintenance expenses increased $49 million primarily due to the following:
•A $42 million increase in transmission expenses primarily due to the June 2025 FERC NOLC order and SPP expenses.
•A $12 million increase in distribution expenses primarily due to overhead line maintenance.
These increases were partially offset by:
•A $13 million decrease in expenses from a customer project to enhance transmission resiliency in 2024.
•Interest Expense increased $29 million primarily due to higher long-term debt balances and a prior year deferral of expenses as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.
•Income Tax Benefit decreased $38 million primarily due to the following:
•A $48 million decrease due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking recorded in 2024.
This decrease was partially offset by:
•A $13 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
94


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
 September 30,September 30,
 2025202420252024
REVENUES    
Electric Generation, Transmission and Distribution$685.5 $612.9 $1,541.5 $1,439.1 
Sales to AEP Affiliates3.5 1.1 5.9 5.7 
Other Revenues4.4 1.4 9.5 17.2 
TOTAL REVENUES693.4 615.4 1,556.9 1,462.0 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation294.2 284.8 595.5 613.7 
Other Operation139.5 112.2 363.2 328.1 
Maintenance36.9 28.7 95.3 81.7 
Depreciation and Amortization67.1 70.6 202.7 202.1 
Taxes Other Than Income Taxes20.8 18.8 59.4 60.2 
TOTAL EXPENSES558.5 515.1 1,316.1 1,285.8 
OPERATING INCOME134.9 100.3 240.8 176.2 
Other Income (Expense):    
Interest Income— 0.2 2.3 0.7 
Allowance for Equity Funds Used During Construction1.1 1.3 7.3 4.6 
Non-Service Cost Components of Net Periodic Benefit Cost2.1 2.9 6.3 8.5 
Interest Expense(40.0)(26.5)(99.6)(70.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)98.1 78.2 157.1 119.8 
Income Tax Expense (Benefit)(31.7)(35.5)(63.9)(102.2)
NET INCOME$129.8 $113.7 $221.0 $222.0 
The common stock of PSO is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
95

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
September 30,September 30,
2025202420252024
Net Income$129.8 $113.7 $221.0 $222.0 
OTHER COMPREHENSIVE LOSS, NET OF TAXES    
Cash Flow Hedges, Net of Tax of $0 and $(2.3) for the Three Months Ended September 30, 2025 and 2024, Respectively, and $(0.3) and $(2.3) for the Nine Months Ended September 30, 2025 and 2024, Respectively
(0.1)(8.6)(1.3)(8.6)
    
TOTAL COMPREHENSIVE INCOME$129.7 $105.1 $219.7 $213.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
96

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 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$157.2 $1,039.3 $1,374.3 $(0.2)$2,570.6 
Common Stock Dividends(35.0)(35.0)
Net Income72.0 72.0 
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2024157.2 1,039.3 1,411.3 (0.2)2,607.6 
Capital Contribution from Parent0.2 0.2 
Common Stock Dividends(35.0)(35.0)
Net Income  36.3  36.3 
TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2024157.2 1,039.5 1,412.6 (0.2)2,609.1 
Common Stock Dividends(35.0)(35.0)
Net Income113.7 113.7 
Other Comprehensive Loss(8.6)(8.6)
TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2024$157.2 $1,039.5 $1,491.3 $(8.8)$2,679.2 
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2024$157.2 $1,041.2 $1,483.6 $3.6 $2,685.6 
Net Income27.5 27.5 
Other Comprehensive Loss(1.2)(1.2)
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2025157.2 1,041.2 1,511.1 2.4 2,711.9 
Capital Contribution from Parent299.9 299.9 
Net Income  63.7  63.7 
TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2025157.2 1,341.1 1,574.8 2.4 3,075.5 
Capital Contribution from Parent375.0 375.0 
Net Income129.8 129.8 
Other Comprehensive Loss(0.1)(0.1)
TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2025$157.2 $1,716.1 $1,704.6 $2.3 $3,580.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

97

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
 September 30,December 31,
 20252024
CURRENT ASSETS  
Cash and Cash Equivalents$3.1 $1.8 
Advances to Affiliates— 232.0 
Accounts Receivable:  
Customers95.6 74.8 
Affiliated Companies41.3 32.6 
Miscellaneous4.7 0.3 
Total Accounts Receivable141.6 107.7 
Fuel5.9 17.1 
Materials and Supplies119.9 108.8 
Risk Management Assets68.1 20.6 
Accrued Tax Benefits19.1 35.5 
Regulatory Asset for Under-Recovered Fuel Costs22.3 64.7 
Prepayments and Other Current Assets18.1 20.2 
TOTAL CURRENT ASSETS398.1 608.4 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation4,347.5 2,772.4 
Transmission1,378.1 1,345.3 
Distribution3,888.8 3,698.8 
Other Property, Plant and Equipment1,269.6 550.0 
Construction Work in Progress454.6 378.8 
Total Property, Plant and Equipment11,338.6 8,745.3 
Accumulated Depreciation and Amortization2,702.7 2,213.0 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET8,635.9 6,532.3 
OTHER NONCURRENT ASSETS  
Regulatory Assets603.5 527.8 
Employee Benefits and Pension Assets77.5 73.6 
Operating Lease Assets126.1 106.2 
Deferred Charges and Other Noncurrent Assets82.9 62.0 
TOTAL OTHER NONCURRENT ASSETS890.0 769.6 
TOTAL ASSETS$9,924.0 $7,910.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
98

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2025 and December 31, 2024
(Unaudited)
 September 30,December 31,
 20252024
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$39.7 $— 
Accounts Payable:  
General285.2 200.5 
Affiliated Companies123.6 59.1 
Long-term Debt Due Within One Year – Nonaffiliated50.6 125.6 
Risk Management Liabilities15.9 5.8 
Customer Deposits114.6 72.9 
Accrued Taxes93.9 33.4 
Accrued Interest39.6 33.1 
Obligations Under Operating Leases11.6 10.4 
Other Current Liabilities88.0 78.6 
TOTAL CURRENT LIABILITIES862.7 619.4 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated3,474.0 2,730.0 
Deferred Income Taxes989.0 930.6 
Regulatory Liabilities and Deferred Investment Tax Credits722.0 689.7 
Asset Retirement Obligations139.1 118.8 
Obligations Under Operating Leases121.6 101.9 
Deferred Credits and Other Noncurrent Liabilities35.4 34.3 
TOTAL NONCURRENT LIABILITIES5,481.1 4,605.3 
TOTAL LIABILITIES6,343.8 5,224.7 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY  
Common Stock – Par Value – $15 Per Share:
  
Authorized – 11,000,000 Shares
  
Issued – 10,482,000 Shares
  
Outstanding – 9,013,000 Shares
157.2 157.2 
Paid-in Capital1,716.1 1,041.2 
Retained Earnings1,704.6 1,483.6 
Accumulated Other Comprehensive Income (Loss)2.3 3.6 
TOTAL COMMON SHAREHOLDER’S EQUITY3,580.2 2,685.6 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$9,924.0 $7,910.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
99

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20252024
OPERATING ACTIVITIES  
Net Income$221.0 $222.0 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization202.7 202.1 
Deferred Income Taxes30.6 (12.7)
Allowance for Equity Funds Used During Construction(7.3)(4.6)
Mark-to-Market of Risk Management Contracts(34.4)(27.9)
Property Taxes(16.1)(14.8)
Deferred Fuel Over/Under-Recovery, Net42.4 90.9 
Change in Other Regulatory Assets(57.2)5.0 
Change in Other Noncurrent Assets(34.7)(24.4)
Change in Other Noncurrent Liabilities14.4 0.8 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(33.9)33.3 
Fuel, Materials and Supplies4.1 12.2 
Accounts Payable142.0 9.6 
Accrued Taxes, Net76.1 54.0 
Other Current Assets(2.1)(15.3)
Other Current Liabilities23.8 (67.0)
Net Cash Flows from Operating Activities571.4 463.2 
INVESTING ACTIVITIES  
Construction Expenditures(534.1)(402.9)
Change in Advances to Affiliates, Net232.0 — 
Acquisitions of Generation Facilities(1,657.3)— 
Other Investing Activities7.8 5.1 
Net Cash Flows Used for Investing Activities(1,951.6)(397.8)
FINANCING ACTIVITIES  
Capital Contribution from Parent674.9 0.2 
Issuance of Long-term Debt – Nonaffiliated793.1 — 
Change in Advances from Affiliates, Net39.7 44.1 
Retirement of Long-term Debt – Nonaffiliated(125.4)(0.4)
Principal Payments for Finance Lease Obligations(2.4)(2.5)
Dividends Paid on Common Stock— (105.0)
Other Financing Activities1.6 0.5 
Net Cash Flows from (Used for) Financing Activities1,381.5 (63.1)
Net Increase in Cash and Cash Equivalents1.3 2.3 
Cash and Cash Equivalents at Beginning of Period1.8 2.5 
Cash and Cash Equivalents at End of Period$3.1 $4.8 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$95.8 $86.4 
Net Cash Paid (Received) for Income Taxes(86.2)(27.2)
Cash Paid (Received) for Transferable Tax Credits(48.0)(76.9)
Noncash Acquisitions Under Finance Leases2.1 1.2 
Construction Expenditures Included in Current Liabilities as of September 30,90.7 76.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
100

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
 2025202420252024
 (in millions of KWhs)
Retail:    
Residential2,016 1,955 4,984 4,855 
Commercial1,699 1,617 4,359 4,287 
Industrial1,375 1,232 3,883 3,873 
Miscellaneous16 17 50 52 
Total Retail5,106 4,821 13,276 13,067 
Wholesale (a)1,562 1,567 4,305 4,281 
Total KWhs6,668 6,388 17,581 17,348 
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.


Summary of Heating and Cooling Degree Days
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
 2025202420252024
 (in degree days)
Actual – Heating— — 726 560 
Normal – Heating— 1 714 722 
Actual – Cooling1,545 1,591 2,589 2,721 
Normal – Cooling1,404 1,439 2,220 2,237 

101

Southwestern Electric Power Company
Reconciliation of 2024 to 2025
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2024 Earnings Attributable to Common Shareholder
$139.1 $277.1 
  
Changes in Revenues: 
Retail Revenues (a)65.2 236.9 
Off-system Sales0.6 (0.9)
Transmission Revenues13.9 34.7 
Other Revenues5.4 3.9 
Total Change in Revenues85.1 274.6 
  
Changes in Expenses and Other: 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation11.7 6.3 
Other Operation and Maintenance(46.5)(16.4)
Depreciation and Amortization(10.3)(36.4)
Taxes Other Than Income Taxes(1.7)(6.1)
Interest Income0.4 (3.0)
Allowance for Equity Funds Used During Construction4.4 4.6 
Non-Service Cost Components of Net Periodic Benefit Cost(0.9)(2.5)
Interest Expense(5.0)(34.7)
Total Change in Expenses and Other(47.9)(88.2)
  
Income Tax Benefit12.8 (110.9)
Equity Earnings of Unconsolidated Subsidiary(0.2)(0.3)
Net Income Attributable to Noncontrolling Interest0.3 1.0 
  
2025 Earnings Attributable to Common Shareholder
$189.2 $353.3 

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

Third Quarter of 2025 Compared to Third Quarter of 2024

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

•Retail Revenues increased $65 million primarily due to the following:
•A $35 million increase in weather-normalized margins across all classes.
•A $35 million increase in rider revenues.
•Transmission Revenues increased $14 million primarily due to continued transmission investment.
•Other Revenues increased $5 million due to increased associated business development revenues driven by costs associated with a third-party construction project.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $12 million primarily due to a current year decrease in amortization of under-recovered deferred fuel regulatory assets primarily driven by lower authorized fuel rates in Arkansas.

102

•Other Operation and Maintenance expenses increased $47 million primarily due to the following:
•A $20 million increase in transmission expenses primarily due to:
•A $10 million increase due to continued transmission investment.
•A $10 million increase in vegetation management expenses.
•A $12 million increase in distribution expenses primarily due to overhead line maintenance.
•A $6 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $10 million primarily due to the amortization of the Storm Recovery Funding securitized assets.
•Interest Expense increased $5 million primarily associated with Storm Recovery Funding securitization bonds.
•Income Tax Benefit increased $13 million primarily due to an increase in PTCs.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

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

•Retail Revenues increased $237 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 $78 million increase in rider revenues.
•Transmission Revenues increased $35 million primarily due to the following:
•A $27 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $13 million increase due to continued transmission investment.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $6 million primarily due to a current year decrease in amortization of under-recovered deferred fuel regulatory assets.
•Other Operation and Maintenance expenses increased $16 million primarily due to the following:
•A $27 million increase in transmission expenses primarily due to:
•A $15 million increase due to continued transmission investment.
•A $10 million increase related to the June 2025 FERC NOLC order.
This increase was partially offset by:
•A $14 million decrease due to a disallowance recorded on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.
•Depreciation and Amortization expenses increased $36 million primarily due to the following:
•A $24 million increase due to a higher depreciable base.
•A $17 million increase due to the amortization of the Storm Recovery Funding securitized assets.
•Taxes Other Than Income Taxes increased $6 million primarily due to an increase in property taxes.
•Interest Expense increased $35 million primarily due to the following:
•A $20 million increase due to a prior year deferral of expenses as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.
•A $17 million increase associated with Storm Recovery Funding securitization bonds.
•Income Tax Benefit decreased $111 million primarily due to the following:
•A $109 million decrease due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking recorded in 2024.
•A $39 million decrease due to an increase in pretax book income.
•A $32 million decrease due to the reversal of a regulatory liability related to the merchant portion of Turk Plant Excess ADIT as a result of the APSC’s denial of SWEPCo’s request to allow the merchant portion of the Turk Plant to serve Arkansas customers recorded in 2024.
These decreases were partially offset by:
•A $42 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $19 million increase due to an increase in PTCs.
103


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
 September 30,September 30,
 2025202420252024
REVENUES    
Electric Generation, Transmission and Distribution$694.3 $625.1 $1,760.7 $1,680.5 
Sales to AEP Affiliates28.2 19.7 63.7 50.5 
(Provision for)/Reversal of – Revenue Refund – Nonaffiliated(4.6)(6.7)(9.1)(187.2)
Other Revenues6.0 0.7 10.1 7.0 
TOTAL REVENUES723.9 638.8 1,825.4 1,550.8 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation192.4 204.1 575.8 582.1 
Other Operation122.1 95.1 326.9 324.3 
Maintenance54.8 35.3 139.7 125.9 
Depreciation and Amortization128.0 117.7 334.0 297.6 
Taxes Other Than Income Taxes35.8 34.1 99.9 93.8 
TOTAL EXPENSES533.1 486.3 1,476.3 1,423.7 
OPERATING INCOME190.8 152.5 349.1 127.1 
Other Income (Expense):   
Interest Income3.5 3.1 8.4 11.4 
Allowance for Equity Funds Used During Construction7.3 2.9 14.3 9.7 
Non-Service Cost Components of Net Periodic Benefit Cost1.7 2.6 5.1 7.6 
Interest Expense(36.9)(31.9)(109.8)(75.1)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS166.4 129.2 267.1 80.7 
Income Tax Expense (Benefit)(23.3)(10.5)(87.9)(198.8)
Equity Earnings of Unconsolidated Subsidiary0.2 0.4 0.8 1.1 
NET INCOME189.9 140.1 355.8 280.6 
Net Income Attributable to Noncontrolling Interest0.7 1.0 2.5 3.5 
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$189.2 $139.1 $353.3 $277.1 
The common stock of SWEPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
104

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2025202420252024
Net Income$189.9 $140.1 $355.8 $280.6 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES    
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2025 and 2024, Respectively, and $(0.1) and $(0.1) for the Nine Months Ended September 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 $(0.1) for the Three Months Ended September 30, 2025 and 2024, Respectively, and $0 and $(0.1) for the Nine Months Ended September 30, 2025 and 2024, Respectively
— (0.1)— (0.2)
TOTAL OTHER COMPREHENSIVE LOSS(0.1)(0.2)(0.2)(0.4)
TOTAL COMPREHENSIVE INCOME189.8 139.9 355.6 280.2 
Total Comprehensive Income Attributable to Noncontrolling Interest0.7 1.0 2.5 3.5 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$189.1 $138.9 $353.1 $276.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
105

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
SWEPCo Common Shareholder  
Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Noncontrolling
Interest		Total
TOTAL EQUITY – DECEMBER 31, 2023$0.1 $1,492.2 $2,281.3 $(3.4)$0.2 $3,770.4 
Common Stock Dividends(50.0)(50.0)
Common Stock Dividends – Nonaffiliated(1.4)(1.4)
Net Income208.1 1.5 209.6 
Other Comprehensive Loss(0.2)(0.2)
TOTAL EQUITY – MARCH 31, 20240.1 1,492.2 2,439.4 (3.6)0.3 3,928.4 
Common Stock Dividends(100.0)(100.0)
Common Stock Dividends – Nonaffiliated    (1.0)(1.0)
Net Income (Loss)  (70.1) 1.0 (69.1)
TOTAL EQUITY – JUNE 30, 20240.1 1,492.2 2,269.3 (3.6)0.3 3,758.3 
Return of Capital to Parent(1.1)(1.1)
Common Stock Dividends(100.0)(100.0)
Common Stock Dividends – Nonaffiliated(1.0)(1.0)
Net Income139.1 1.0 140.1 
Other Comprehensive Loss(0.2)(0.2)
TOTAL EQUITY – SEPTEMBER 30, 2024$0.1 $1,491.1 $2,308.4 $(3.8)$0.3 $3,796.1 
TOTAL EQUITY – DECEMBER 31, 2024$0.1 $1,549.7 $2,352.5 $2.3 $0.4 $3,905.0 
Common Stock Dividends – Nonaffiliated(1.0)(1.0)
Net Income48.5 1.0 49.5 
Other Comprehensive Loss(0.1)(0.1)
TOTAL EQUITY – MARCH 31, 20250.1 1,549.7 2,401.0 2.2 0.4 3,953.4 
Capital Contribution from Parent450.6 450.6 
Common Stock Dividends – Nonaffiliated    (1.0)(1.0)
Net Income  115.6  0.8 116.4 
TOTAL EQUITY – JUNE 30, 20250.1 2,000.3 2,516.6 2.2 0.2 4,519.4 
Common Stock Dividends – Nonaffiliated(0.9)(0.9)
Net Income189.2 0.7 189.9 
Other Comprehensive Loss(0.1)(0.1)
TOTAL EQUITY – SEPTEMBER 30, 2025$0.1 $2,000.3 $2,705.8 $2.1 $— $4,708.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
106

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
 September 30,December 31,
 20252024
CURRENT ASSETS  
Cash and Cash Equivalents $2.7 $1.2 
Restricted Cash
(September 30, 2025 and December 31, 2024 Amounts Include $7.8 and $3.4, Respectively, Related to Storm Recovery Funding)
7.8 3.4 
Advances to Affiliates269.7 2.3 
Accounts Receivable:  
Customers39.7 34.5 
Affiliated Companies74.3 54.1 
Miscellaneous7.0 9.2 
Total Accounts Receivable121.0 97.8 
Fuel 76.9 86.5 
Materials and Supplies
(September 30, 2025 and December 31, 2024 Amounts Include $1.1 and $1.5, Respectively, Related to Sabine)
85.0 81.4 
Risk Management Assets57.8 18.1 
Accrued Tax Benefits28.8 26.0 
Regulatory Asset for Under-Recovered Fuel Costs106.7 106.6 
Prepayments and Other Current Assets17.8 14.7 
TOTAL CURRENT ASSETS774.2 438.0 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation5,335.2 5,287.5 
Transmission3,066.8 2,863.8 
Distribution3,170.3 3,007.1 
Other Property, Plant and Equipment
(September 30, 2025 and December 31, 2024 Amounts Include $125.2 and $166.8, Respectively, Related to Sabine)
909.5 940.4 
Construction Work in Progress753.4 627.3 
Total Property, Plant and Equipment13,235.2 12,726.1 
Accumulated Depreciation and Amortization
(September 30, 2025 and December 31, 2024 Amounts Include $125.2 and $166.8, Respectively, Related to Sabine)
3,443.6 3,280.0 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET9,791.6 9,446.1 
OTHER NONCURRENT ASSETS  
Regulatory Assets922.2 921.3 
Securitized Assets
(September 30, 2025 and December 31, 2024 Amounts Include $319.5 and $331.4, Respectively, Related to Storm Recovery Funding)
319.5 331.4 
Deferred Charges and Other Noncurrent Assets374.6 358.2 
TOTAL OTHER NONCURRENT ASSETS1,616.3 1,610.9 
TOTAL ASSETS$12,182.1 $11,495.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
107

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2025 and December 31, 2024
(Unaudited)
 September 30,December 31,
 20252024
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$— $275.0 
Accounts Payable:  
General324.9 265.5 
Affiliated Companies112.3 57.1 
Short-term Debt – Nonaffiliated7.7 5.5 
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2025 and December 31, 2024 Amounts Include $16.6 and $22.7, Respectively, Related to Storm Recovery Funding)
516.6 22.7 
Risk Management Liabilities4.4 2.3 
Customer Deposits78.5 75.4 
Accrued Taxes120.1 48.6 
Accrued Interest40.1 40.6 
Obligations Under Operating Leases7.0 8.2 
Provision for Refund81.6 70.8 
Other Current Liabilities145.8 159.9 
TOTAL CURRENT LIABILITIES1,439.0 1,031.6 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated
(September 30, 2025 and December 31, 2024 Amounts Include $304.3 and $308.7, Respectively, Related to Storm Recovery Funding)
3,456.0 3,958.1 
Deferred Income Taxes1,372.4 1,271.3 
Regulatory Liabilities and Deferred Investment Tax Credits564.6 610.8 
Asset Retirement Obligations260.7 257.5 
Employee Benefits and Pension Obligations40.1 46.5 
Obligations Under Operating Leases131.6 137.5 
Provision for Refund43.5 107.8 
Storm Reserve106.7 106.2 
Deferred Credits and Other Noncurrent Liabilities59.2 62.7 
TOTAL NONCURRENT LIABILITIES6,034.8 6,558.4 
TOTAL LIABILITIES7,473.8 7,590.0 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
EQUITY  
Common Stock – Par Value – $18 Per Share:
  
Authorized – 3,680 Shares
  
Outstanding – 3,680 Shares
0.1 0.1 
Paid-in Capital2,000.3 1,549.7 
Retained Earnings2,705.8 2,352.5 
Accumulated Other Comprehensive Income (Loss)2.1 2.3 
TOTAL COMMON SHAREHOLDER’S EQUITY4,708.3 3,904.6 
Noncontrolling Interest— 0.4 
TOTAL EQUITY4,708.3 3,905.0 
TOTAL LIABILITIES AND EQUITY$12,182.1 $11,495.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
108

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2025 and 2024
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20252024
OPERATING ACTIVITIES  
Net Income$355.8 $280.6 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
Depreciation and Amortization334.0 297.6 
Deferred Income Taxes23.4 (117.1)
Allowance for Equity Funds Used During Construction(14.3)(9.7)
Mark-to-Market of Risk Management Contracts(36.5)(23.3)
Property Taxes(23.2)(23.7)
Deferred Fuel Over/Under-Recovery, Net90.9 134.3 
Provision for Refund – Turk Plant— 100.0 
Change in Other Noncurrent Assets(51.2)(41.3)
Change in Other Noncurrent Liabilities(103.4)(46.0)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(23.2)(2.4)
Fuel, Materials and Supplies6.0 26.2 
Accounts Payable135.9 7.6 
Accrued Taxes, Net68.7 65.1 
Provision for Refund – Turk Plant— 60.0 
Other Current Assets0.6 (7.0)
Other Current Liabilities(10.3)(51.5)
Net Cash Flows from Operating Activities753.2 649.4 
INVESTING ACTIVITIES  
Construction Expenditures(654.0)(539.6)
Change in Advances to Affiliates, Net(267.4)(0.6)
Other Investing Activities11.2 10.9 
Net Cash Flows Used for Investing Activities(910.2)(529.3)
FINANCING ACTIVITIES  
Capital Contribution from Parent450.6 — 
Return of Capital to Parent— (1.1)
Issuance of Long-term Debt – Nonaffiliated0.7 — 
Change in Short-term Debt – Nonaffiliated2.2 0.3 
Change in Advances from Affiliates, Net(275.0)148.7 
Retirement of Long-term Debt – Nonaffiliated(11.1)— 
Principal Payments for Finance Lease Obligations(3.1)(13.0)
Dividends Paid on Common Stock— (250.0)
Dividends Paid on Common Stock – Nonaffiliated(2.9)(3.4)
Other Financing Activities1.5 0.4 
Net Cash Flows from (Used for) Financing Activities162.9 (118.1)
Net Increase in Cash, Cash Equivalents and Restricted Cash5.9 2.0 
Cash, Cash Equivalents and Restricted Cash at Beginning of Period4.6 2.4 
Cash, Cash Equivalents and Restricted Cash at End of Period$10.5 $4.4 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$118.5 $107.1 
Net Cash Paid (Received) for Income Taxes(60.9)(11.2)
Cash Paid (Received) for Transferable Tax Credits(54.2)(69.4)
Noncash Acquisitions Under Finance Leases2.6 1.9 
Construction Expenditures Included in Current Liabilities as of September 30,115.7 84.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.
109

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS

The condensed notes to condensed financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise:
NoteRegistrantPage
Number
Significant Accounting MattersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
111
New Accounting StandardsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
113
Comprehensive IncomeAEP
115
Rate MattersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
117
Commitments, Guarantees and ContingenciesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
135
Acquisitions and DispositionsAEP, AEPTCo, PSO
138
Benefit PlansAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
140
Business SegmentsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
143
Derivatives and HedgingAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
149
Fair Value MeasurementsAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
159
Income TaxesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
173
Voluntary Severance ProgramAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
176
Financing ActivitiesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
177
Variable Interest EntitiesAEP
185
Property, Plant and EquipmentAEP, PSO, SWEPCo
188
Revenue from Contracts with CustomersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
189
110

1.  SIGNIFICANT ACCOUNTING MATTERS

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

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC.  Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant.  Net income for the three and nine months ended September 30, 2025 is not necessarily indicative of results that may be expected for the year ending December 31, 2025.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2024 financial statements and notes thereto, which are included in the 2024 Annual Reports.

Earnings Per Share (EPS) (Applies to AEP)

Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted-average number of common shares outstanding during the period.  Diluted EPS is calculated by adjusting the weighted-average outstanding common shares, assuming conversion of all potentially dilutive securities. Dilutive securities are primarily related to forward sale of equity agreements and restricted stock units. See Note 13 - Financing Activities for more information regarding the forward sale of equity agreements.

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

Three Months Ended September 30,
20252024
(in millions, except per share data)
 $/share$/share
Earnings Attributable to AEP Common Shareholders$972.0  $959.6  
Weighted-Average Number of Basic AEP Common Shares Outstanding534.9 $1.82 532.2 $1.80 
Weighted-Average Dilutive Effect3.1 (0.01)1.4 — 
Weighted-Average Number of Diluted AEP Common Shares Outstanding538.0 $1.81 533.6 $1.80 

Nine Months Ended September 30,
20252024
(in millions, except per share data)
 $/share$/share
Earnings Attributable to AEP Common Shareholders$2,998.0  $2,303.0  
Weighted-Average Number of Basic AEP Common Shares Outstanding534.2 $5.61 529.2 $4.35 
Weighted-Average Dilutive Effect2.2 (0.02)1.3 (0.01)
Weighted-Average Number of Diluted AEP Common Shares Outstanding536.4 $5.59 530.5 $4.34 

There were no antidilutive shares outstanding as of September 30, 2025 and 2024.
111

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

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

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statements of cash flows:
September 30, 2025
AEPAEP TexasAPCoSWEPCo
(in millions)
Cash and Cash Equivalents$1,067.7 $0.1 $3.9 $2.7 
Restricted Cash39.1 7.3 10.8 7.8 
Total Cash, Cash Equivalents and Restricted Cash$1,106.8 $7.4 $14.7 $10.5 

December 31, 2024
AEPAEP TexasAPCoSWEPCo
(in millions)
Cash and Cash Equivalents$202.9 $0.1 $3.9 $1.2 
Restricted Cash43.1 23.5 16.2 3.4 
Total Cash, Cash Equivalents and Restricted Cash$246.0 $23.6 $20.1 $4.6 

Supplementary Cash Flow Information (Applies to AEP)
Nine Months Ended September 30,
Cash Flow Information20252024
(in millions)
Cash Paid (Received) for:
Interest, Net of Capitalized Amounts$1,315.1 $1,247.3 
Income Taxes, Net60.1 87.9 
Sale of Transferable Tax Credits(102.2)(163.7)
Noncash Investing and Financing Activities:
Acquisitions Under Finance Leases30.0 24.5 
Construction Expenditures Included in Current Liabilities as of September 30,1,168.8 1,015.1 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,1.4 8.2 

112

2. NEW ACCOUNTING STANDARDS

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

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

SEC Climate Disclosure Rule

In March 2024, the SEC adopted final rules that would require registrants to disclose certain climate-related information in registration statements and annual reports. The final rules require registrants to disclose, among other things, material climate-related risks, activities to mitigate such risks and information about a registrant’s board of directors oversight and management’s role in managing material climate-related risks. The final rules also require registrants to provide information related to any climate-related targets or goals that are material to a registrant’s business, results of operations or financial condition. Litigation challenging the new rules was filed by multiple parties in multiple jurisdictions, which have been consolidated and assigned to the U.S. Court of Appeals for the Eighth Circuit. In April 2024, the SEC issued an order staying the final climate disclosure rules pending the completion of judicial review at the Court of Appeals. While a majority of the reporting requirements would be applicable to the fiscal year beginning in 2025, with the addition of assurance reporting for GHG emissions starting in 2029 for large accelerated filers, the SEC subsequently clarified in its briefing that it would address a new effective date for the rules at the conclusion of its stay of the rules. In March 2025, the SEC announced that it voted to end its defense of the final climate disclosure rules. In April 2025, 18 states filed a motion to intervene in the case and to hold the case in abeyance until the SEC takes action to amend or rescind the rules. In July 2025, the SEC filed a status report stating that it does not intend to review or reconsider the rules and asked the Court of Appeals to make a ruling on the case. In September 2025, the Court of Appeals issued an order holding the case in abeyance until the SEC either formally defends the rules or initiates a new rulemaking process for reconsideration. The Registrants are currently evaluating the status of the rules and the impact of the final rules on their respective consolidated financial statements and related disclosures.

ASU 2023-07 “Improvements to Reportable Segment Disclosures” (ASU 2023-07)

In November 2023, the FASB issued ASU 2023-07, to address investors’ observations that there is limited information disclosed about segment expenses and to better understand expense categories and amounts included in segment profit or loss. The new standard requires annual and interim disclosure of (a) the categories and amounts of significant segment expenses (determined by management using both qualitative and quantitative factors) that are regularly provided to the CODM and included within each reported measure of segment profit or loss, (b) the amounts and a qualitative description of “other segment items”, defined as the difference between reported segment revenues less the significant segment expenses and each reported measure of segment profit or loss disclosed, (c) reportable segment profit or loss and assets that are currently only required annually, (d) the CODM’s title and position, and an explanation of how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources and (e) a requirement that entities with a single reportable segment provide all disclosures required by ASU 2023-07 and all existing segment disclosures in Topic 280. Additionally, this new standard allows disclosure of one or more additional profit or loss measures if the CODM uses more than one measure provided that at least one of the disclosed measures is determined in a manner “most consistent with the measurement principles under GAAP”. If multiple measures are presented, additional disclosure is required about how the CODM uses each measure to assess performance and decide how to allocate resources.

Management adopted ASU 2023-07 and its related implementation guidance effective January 1, 2024 for the annual reporting period and applied the amendments retrospectively to all prior periods presented in the annual consolidated financial statements. The amendments for interim periods were adopted in the fiscal year beginning on January 1, 2025. The adoption of the new standard did not impact the results of operations, statements of financial position or cash flows. See Note 8 - Business Segments for additional information.


113

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

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

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

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

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

The amendments in the new standard may be applied on either a prospective or retrospective basis for public business entities for fiscal years beginning after December 15, 2024 with early adoption permitted. Management will adopt the amendments to this standard prospectively beginning with the Annual Report on Form 10-K for the fiscal year ending December 31, 2025.

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

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

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

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

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

The amendments in the new standard may be applied on either a retrospective, prospective or modified prospective basis for public business entities for fiscal years beginning after December 15, 2027 with early adoption permitted. Management is evaluating the new standard and has not yet determined when, or the method by which, the Registrants will adopt its amendments.
114

3.  COMPREHENSIVE INCOME

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

Presentation of Comprehensive Income

The following tables provide AEP’s components of changes in AOCI and details of reclassifications from AOCI.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional information.

 Cash Flow HedgesPension 
Three Months Ended September 30, 2025CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of June 30, 2025$91.5 $0.2 $(104.3)$(12.6)
Change in Fair Value Recognized in AOCI, Net of Tax(17.1)(0.1)— (17.2)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)3.2 — — 3.2 
Interest Expense (a)— (0.9)— (0.9)
Amortization of Prior Service Cost (Credit)— — (0.2)(0.2)
Amortization of Actuarial (Gains) Losses— — 0.5 0.5 
Reclassifications from AOCI, before Income Tax (Expense) Benefit3.2 (0.9)0.3 2.6 
Income Tax (Expense) Benefit0.7 (0.2)0.1 0.6 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit2.5 (0.7)0.2 2.0 
Net Current Period Other Comprehensive Income (Loss)(14.6)(0.8)0.2 (15.2)
Balance in AOCI as of September 30, 2025$76.9 $(0.6)$(104.1)$(27.8)

 Cash Flow HedgesPension 
Three Months Ended September 30, 2024CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of June 30, 2024$103.7 $9.3 $(153.0)$(40.0)
Change in Fair Value Recognized in AOCI, Net of Tax(28.8)(24.5)— (53.3)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)0.1 — — 0.1 
Interest Expense (a)— 8.8 — 8.8 
Amortization of Prior Service Cost (Credit)— — (1.4)(1.4)
Amortization of Actuarial (Gains) Losses— — 0.7 0.7 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.1 8.8 (0.7)8.2 
Income Tax (Expense) Benefit0.1 1.8 (0.1)1.8 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit— 7.0 (0.6)6.4 
Net Current Period Other Comprehensive Loss(28.8)(17.5)(0.6)(46.9)
Balance in AOCI as of September 30, 2024$74.9 $(8.2)$(153.6)$(86.9)
115

 Cash Flow HedgesPension 
Nine Months Ended September 30, 2025CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of December 31, 2024$98.5 $3.3 $(104.9)$(3.1)
Change in Fair Value Recognized in AOCI, Net of Tax(14.9)(1.1)— (16.0)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)(8.5)— — (8.5)
Interest Expense (a)— (3.5)— (3.5)
Amortization of Prior Service Cost (Credit)— — (0.6)(0.6)
Amortization of Actuarial (Gains) Losses— — 1.6 1.6 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(8.5)(3.5)1.0 (11.0)
Income Tax (Expense) Benefit(1.8)(0.7)0.2 (2.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(6.7)(2.8)0.8 (8.7)
Net Current Period Other Comprehensive Income (Loss)(21.6)(3.9)0.8 (24.7)
Balance in AOCI as of September 30, 2025$76.9 $(0.6)$(104.1)$(27.8)

 Cash Flow HedgesPension 
Nine Months Ended September 30, 2024CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of December 31, 2023$104.9 $(8.1)$(152.3)$(55.5)
Change in Fair Value Recognized in AOCI, Net of Tax(16.3)(5.2)— (21.5)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)(17.4)— — (17.4)
Interest Expense (a)— 6.5 — 6.5 
Amortization of Prior Service Cost (Credit)— — (4.0)(4.0)
Amortization of Actuarial (Gains) Losses— — 2.4 2.4 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(17.4)6.5 (1.6)(12.5)
Income Tax (Expense) Benefit(3.7)1.4 (0.3)(2.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(13.7)5.1 (1.3)(9.9)
Net Current Period Other Comprehensive Loss(30.0)(0.1)(1.3)(31.4)
Balance in AOCI as of September 30, 2024$74.9 $(8.2)$(153.6)$(86.9)

(a)Amounts reclassified to the referenced line item on the statements of income.
116

4.  RATE MATTERS

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

As discussed in the 2024 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2024 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2025 and updates the 2024 Annual Report.

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

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

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets is not deemed recoverable, it could reduce future net income and cash flows and impact financial condition.

Regulated Generating Units that have been Retired

SWEPCo

In March 2023, the Pirkey Plant was retired. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana jurisdictional share of the Pirkey Plant, through a separate rider, through 2032. As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo requested recovery including a weighted average cost of capital carrying charge in its 2025 Arkansas Base Rate Case. In August 2025 and October 2025, APSC staff and certain intervenors recommended recovery of the Arkansas jurisdictional share of the remaining net book value of the Pirkey Plant over 20 years with no debt or equity return. See the “2025 Arkansas Base Rate Case” section below for additional information. In July 2023, Texas ALJs issued a PFD that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected this conclusion in the ALJ’s July 2023 PFD. SWEPCo requested recovery of the Texas jurisdictional share of the remaining net book value of the Pirkey Plant in its 2025 Texas Base Rate Case. See the “2025 Texas Base Rate Case” section below for additional information. As of September 30, 2025, the Arkansas and Texas jurisdictional shares of the net book value of the Pirkey Plant were $117 million. To the extent any portion of the Arkansas and Texas jurisdictional shares of the net book value of the Pirkey Plant are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Regulated Generating Units to be Retired

PSO

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. Following the 2024 Oklahoma Base Rate Case, PSO continues to recover Northeastern Plant, Unit 3 through 2040. In April 2025, PSO and the ODEQ finalized a second amended regional haze agreement that would allow continued operation of the Northeastern Plant, Unit 3, on natural gas, through May 31, 2041. This agreement is contingent upon approval by the Federal EPA in the form of a revised SIP. The ODEQ is in the process of preparing a SIP submission for the Federal EPA’s review and approval.

SWEPCo

In November 2020, management announced that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation. In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively.

117

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of September 30, 2025, of generating facilities planned for retirement:
PlantNet Book ValueAccelerated Depreciation Regulatory AssetCost of Removal
Regulatory Liability		Projected
Retirement Date		Current Authorized
Recovery Period		Annual
Depreciation (a)
(dollars in millions)
Northeastern Plant, Unit 3$73.9 $212.8 $21.2 (b)2026(c)$16.1 
Welsh Plant, Units 1 and 3278.8 206.2 57.6 (d)2028(e)(f)46.5 

(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with the removal of Northeastern Plant, Unit 3, after retirement.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with the removal of Welsh Plant, Units 1 and 3, after retirement.
(e)Represents projected retirement date of coal assets.
(f)Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo)

In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station. The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through rate riders. As of September 30, 2025, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $67 million, including materials and supplies, net of cost of removal collected in rates. Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses and are subject to prudency determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of September 30, 2025, SWEPCo had a net under-recovered fuel balance of $23 million, inclusive of costs related to the Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event.

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $35 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of up to $55 million, including denial of recovery of the $35 million deferral, with refunds to customers over five years. In February 2024, an ALJ issued a final recommendation which included a proposed $55 million refund to customers and the denial of recovery of the $35 million deferral. SWEPCo filed a motion to present oral arguments with the LPSC to dispute the ALJ’s recommendations. In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the fuel recovery dispute and resulted in a fuel disallowance of $11 million. The remaining $24 million regulatory asset balance will be recovered over three years with interest.

In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $48 million of Oxbow mine related costs through 2035.

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


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Pirkey Plant and Related Fuel Operations (Applies to AEP and SWEPCo)

In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or is seeking recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of September 30, 2025, SWEPCo’s share of the net investment in the Pirkey Plant was $206 million, including materials and supplies, net of cost of removal. See the “Regulated Generating Units that have been Retired” section above for additional information. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of March 31, 2023, SWEPCo fuel deliveries, including billings of all fixed costs, from Sabine ceased. Additionally, as of September 30, 2025, SWEPCo had a net under-recovered fuel balance of $23 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Remaining operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses.

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

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

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


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Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)
AEP
September 30,December 31,
20252024
 Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return  
Welsh Plant, Units 1 and 3 Accelerated Depreciation$206.2 $168.6 
Pirkey Plant Accelerated Depreciation134.1 121.3 
Storm-Related Costs53.5 51.0 
Unrecovered Winter Storm Fuel Costs (a)47.2 70.7 
Unified Tracking Mechanism Deferred Costs39.2 — 
Other Regulatory Assets Pending Final Regulatory Approval30.9 20.7 
Regulatory Assets Currently Not Earning a Return  
Plant Retirement Costs – Asset Retirement Obligation Costs (b)386.5 357.4 
Storm-Related Costs (c)202.2 300.8 
2024-2025 Virginia Biennial Under-Earnings166.0 78.4 
NOLC Costs (d)95.9 92.8 
Other Regulatory Assets Pending Final Regulatory Approval130.8 86.3 
Total Regulatory Assets Pending Final Regulatory Approval$1,492.5 $1,348.0 

(a)Includes $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of September 30, 2025 and December 31, 2024, respectively. See “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.
(b)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.
(c)Includes $40 million of West Virginia jurisdictional storm operation and maintenance costs as of September 30, 2025 that are subject to a future final securitization financing order from the WVPSC.
(d)Approved for collection through rates, subject to refund, for the Oklahoma and SWEPCo-Texas jurisdictions.

AEP Texas
September 30,December 31,
20252024
Noncurrent Regulatory Assets(in millions)
Regulatory Assets Currently Earning a Return
Storm-Related Costs$41.3 $41.3 
Unified Tracking Mechanism Deferred Costs39.2 — 
System Resiliency Plan Deferred Costs8.6 — 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs34.4 13.1 
Deferred Pension and OPEB Costs24.7 15.6 
Line Inspection Costs5.8 5.8 
Other Regulatory Assets Pending Final Regulatory Approval2.9 1.3 
Total Regulatory Assets Pending Final Regulatory Approval$156.9 $77.1 


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APCo
September 30,December 31,
20252024
Noncurrent Regulatory Assets(in millions)
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval$1.5 $1.1 
Regulatory Assets Currently Not Earning a Return  
Plant Retirement Costs – Asset Retirement Obligation Costs (a)305.8 282.1 
2024-2025 Virginia Biennial Under-Earnings166.0 78.4 
Storm-Related Costs – West Virginia (b)49.6 144.2 
Pension Settlement16.7 17.8 
Virginia Retail Consumables Deferral12.3 — 
Other Regulatory Assets Pending Final Regulatory Approval20.7 11.9 
Total Regulatory Assets Pending Final Regulatory Approval$572.6 $535.5 

(a)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.
(b)Includes $40 million of West Virginia jurisdictional storm operation and maintenance costs as of September 30, 2025 that are subject to a future final securitization financing order from the WVPSC.


 I&M
September 30,December 31,
20252024
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval$3.3 $6.4 
Regulatory Assets Currently Not Earning a Return  
Plant Retirement Costs – Asset Retirement Obligation Costs (a)77.4 74.0 
Storm-Related Costs – Indiana29.3 6.3 
NOLC Costs – Indiana (b)— 26.7 
Other Regulatory Assets Pending Final Regulatory Approval1.7 1.6 
Total Regulatory Assets Pending Final Regulatory Approval$111.7 $115.0 

(a)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.
(b)In the first quarter of 2025, the IURC approved the stand-alone treatment of NOLCs.

 OPCo
September 30,December 31,
20252024
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval$0.9 $0.4 
Regulatory Assets Currently Not Earning a Return  
Other Regulatory Assets Pending Final Regulatory Approval— 0.1 
Total Regulatory Assets Pending Final Regulatory Approval$0.9 $0.5 
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 PSO
September 30,December 31,
20252024
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Not Earning a Return  
NOLC Costs (a)$25.4 $16.4 
Storm-Related Costs 22.4 4.9 
Generation PBA and Delayed Retirement Deferral7.7 — 
Pension Settlement7.4 7.8 
Other Regulatory Assets Pending Final Regulatory Approval7.8 1.2 
Total Regulatory Assets Pending Final Regulatory Approval$70.7 $30.3 

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

SWEPCo
September 30,December 31,
20252024
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return  
Welsh Plant, Units 1 and 3 Accelerated Depreciation$206.2 $168.6 
Pirkey Plant Accelerated Depreciation134.1 121.3 
Unrecovered Winter Storm Fuel Costs (a)47.2 70.7 
Dolet Hills Power Station Accelerated Depreciation (b)12.4 11.8 
Storm-Related Costs12.2 9.7 
Other Regulatory Assets Pending Final Regulatory Approval4.3 1.1 
Regulatory Assets Currently Not Earning a Return  
NOLC Costs (c)70.5 49.6 
Storm-Related Costs - Louisiana, Texas44.9 39.9 
Other Regulatory Assets Pending Final Regulatory Approval19.5 18.7 
Total Regulatory Assets Pending Final Regulatory Approval$551.3 $491.4 

(a)Includes $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of September 30, 2025 and December 31, 2024, respectively. See “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.
(b)Amounts include the FERC jurisdiction.
(c)Approved for collection through rates, subject to refund, for Texas jurisdiction.

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

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

AEP Texas Interim Transmission and Distribution Rates

Through September 30, 2025, AEP Texas’ cumulative revenues from transmission and distribution interim base rate increases that are subject to review are estimated to be approximately $79 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition.

Texas Legislation

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

The UTM permits a qualifying electric utility to defer all or a portion of costs associated with its eligible transmission and distribution capital investments, including depreciation expense and carrying costs, as a regulatory asset. The tracking mechanism is available through 2035 and is an alternative to the existing capital tracking mechanisms in Texas. As a result of the new legislation, AEP Texas deferred approximately $39 million of eligible costs through September 2025 as a regulatory asset.

In October 2025, AEP Texas submitted its first filing with the PUCT seeking recovery of eligible costs through the UTM established by HB 5247. This filing combined three recovery mechanisms (Interim Transmission Cost of Service and Distribution Cost Recovery Factor capital trackers and the Transmission Cost Recovery Factor) into a single filing. The capital tracker incremental revenue requirement sought in this filing is $109 million, including a request to recover, over a 12-month period, $42 million of eligible costs related to UTM deferrals and $2 million of eligible costs related to the System Resiliency Plan deferrals, both inclusive of equity carrying charges through the July 2025 test year period end. Investments included in the UTM and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate review before the PUCT. If any of these deferred costs are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

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

ENEC (Expanded Net Energy Cost) Filings

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

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

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

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

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

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

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

Virginia Fuel Adjustment Clause (FAC) Review

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

In September 2024, APCo submitted its annual Virginia fuel cost filing with the Virginia SCC proposing no change in annual APCo Virginia FAC rates charged to customers. In January 2025, an intervening party recommended a minimum fuel under-recovery disallowance of $20 million related to alleged imprudent operations of Amos and Mountaineer generating units during October 2021 and November 2021. There were no other recommended disallowances by intervenors or Virginia Staff regarding APCo’s historical period Virginia fuel under-recovery balance through October 31, 2024. Virginia Staff recommended that the Virginia SCC close APCo’s open review periods related to 2021 and 2022 Virginia fuel costs. A hearing was held in February 2025. In March 2025, the Hearing Examiner re-opened the record to obtain additional information to resolve certain issues. In April 2025, APCo and an intervenor submitted supplemental testimony with the intervenor continuing to recommend a $20 million disallowance. A hearing was held in May 2025. In June 2025, the Hearing Examiner issued a report recommending no disallowance. An order is anticipated from the Virginia SCC in the fourth quarter of 2025.

If any fuel costs are not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

2024 West Virginia Base Rate Case

In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $251 million annual increase in base rates based upon a proposed 10.8% ROE and a proposed capital structure of 52% debt and 48% common equity. The requested net annual increase in base rates excludes the Companies’ proposed $94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $118 million in previously deferred major storm expenses over a three-year period plus a carrying charge on the deferral balance, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses.
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The Companies’ November 2024 West Virginia base rate filing also included two sets of alternative frameworks to simplify rates and customer bills and provide predictable future rate increases. The Companies’ first framework includes: (a) securitization, (b) approval of a major storm expense recovery and tracking mechanism and (c) freezing of OATT revenues in the ENEC. This framework includes securitization in a concurrent proceeding of approximately $2.4 billion of West Virginia jurisdictional assets. Securitization of those items could reduce the Companies’ combined requested increase in annual base rates to $37 million. See the “2025 West Virginia Securitization Filing” section below for additional information.

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

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

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

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

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

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


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2025 West Virginia Securitization Filing

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

In August 2025, the WVPSC issued an interim order stating that it will approve the Companies’ future securitization of the generation plant assets, ENEC under-recovery balances, environmental costs and deferred storm operation and maintenance costs.

In September 2025, and as directed by the WVPSC in the August 2025 interim order described above, the Companies submitted an updated proposed financing order that reflected additional ENEC under-recovery balances for costs incurred in 2025 and additional storm operation and maintenance deferral balances for the impacts of Hurricane Helene and winter storms Blair, Harlow and Jett. WPCo forecasted CCR and ELG amounts below related to the Mitchell Plant are subject to change pending a fourth quarter 2025 KPSC ruling on KPCo’s June 2025 CPCN filing that would allow KPCo to continue taking a 50% share of energy and capacity from the Mitchell Plant to serve KPCo customers beyond December 31, 2028. See “Mitchell Plant Filing for Certificate of Public Convenience and Necessity” section below for additional information. All amounts in the table below are subject to further review in a future final securitization financing order that the Companies expect will be issued by the WVPSC in the fourth quarter of 2025. See the summarization of the proposed securitization items in the table below:

Proposed Securitized ItemsAPCoWPCoTotal
(in millions)
Undepreciated Utility Plant Balances of Amos, Mitchell and Mountaineer (as of December 31, 2022)$1,145.5 $558.7 $1,704.2 
ENEC Under-Recovery Regulatory Assets 166.6 245.8 412.4 
Forecasted Undepreciated CCR and ELG Investments of Amos, Mitchell and Mountaineer (as of November 30, 2024)87.6 149.2 236.8 
Deferred Storm O&M Expense Regulatory Assets 155.0 2.9 157.9 
Upfront Financing Costs10.4 5.9 16.3 
Total$1,565.1 $962.5 $2,527.6 

Upon receipt of the final financing order, the Companies expect to proceed with the securitization bonds issuance process and to complete the securitization in the first half of 2026, subject to market conditions.

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

2025 Virginia Securitization Filing

In July 2025, APCo filed a request with the Virginia SCC to finance, through the issuance of proposed 20-year securitization bonds, approximately $1.4 billion of Virginia jurisdictional undepreciated property balances and a major storm operation and maintenance regulatory asset deferral balance. This proposed securitization included: (a) $1.2 billion of undepreciated Virginia jurisdictional plant balances as of December 31, 2023 for the Amos and Mountaineer Plants and (b) $141 million of Virginia jurisdictional major storm other operation and maintenance expenses deferred during the 2024-2025 biennial period. In September 2025, Virginia SCC staff submitted testimony concluding that all costs proposed by APCo for securitization are eligible for securitization in accordance with Virginia law. While also concluding that APCo’s proposed securitization of the Amos and Mountaineer Plants over 20 years offers benefits to customers through rate relief, Virginia SCC staff took no position on APCo’s proposed securitization of major storm other operation and maintenance expenses due to the apparent lack of significant benefit or cost savings for customers. In October 2025, the Hearing Examiner recommended the Virginia SCC approve the requested $1.4 billion for securitization. The Virginia SCC’s final order is due in November 2025.


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ETT Rate Matters (Applies to AEP)

2025 ETT Base Rate Case

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

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

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

Michigan Power Supply Cost Recovery (PSCR) Reconciliation

2023 PSCR Reconciliation

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

2024 PSCR Reconciliation

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

Indiana Earnings Test

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

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

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


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KPCo Rate Matters (Applies to AEP)

Investigation of the Service, Rates and Facilities of KPCo

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

2023 Kentucky Base Rate and Securitization Case

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

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

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

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

Mitchell Plant Filing for Certificate of Public Convenience and Necessity

KPCo and WPCo each currently hold a 50% ownership interest in the Mitchell Plant and related CCR investments that have been placed in service. In July 2021, the KPSC rejected KPCo’s ELG compliance plan for KPCo’s 50% ownership share of ELG investments at the Mitchell Plant that would allow KPCo to take capacity and energy to serve customers beyond December 31, 2028. As a result of this order, WPCo holds a 100% interest in Mitchell Plant ELG investments that have been placed in service. In addition, WPCo also holds a greater than 50% ownership share of certain non-ELG capital investments made at Mitchell Plant which will continue to be used in the operation of Mitchell Plant beyond 2028.


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

As of September 30, 2025, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal and including CWIP and inventory, was $529 million.

If any costs related to this CPCN filing are disallowed, it could reduce future net income and cash flows and impact financial condition.

2025 Kentucky Base Rate Case

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

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

If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters (Applies to AEP and OPCo)

OVEC Cost Recovery Audits

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

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

In February and March 2025, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2021-2023 audit period were imprudent and should be disallowed. Management disagrees with these claims and is unable to predict the impact of these disputes. A hearing is scheduled for November 2025. If any costs are disallowed or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.
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Ohio Legislation (HB 15)

Ohio House Bill 15 (HB 15) was approved by the Ohio legislature in April 2025 and signed into law by the Governor of Ohio in May 2025. HB 15 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, through the third quarter of 2025, OPCo recorded a $24 million reduction to its OVEC-related purchased power regulatory asset for deferred net costs that are no longer probable of future recovery. Management is unable to predict the future impact to net income, cash flows and financial condition arising from the future changes in OPCo’s rate setting mechanisms and the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and the market revenues OPCo receives from that purchased power.

2025 Ohio Base Rate Case

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

In October 2025, the PUCO staff filed its required report recommending a net annual decrease in distribution base rates ranging, from $12 million to $28 million, based upon an ROE range of 9.33% to 9.84%. The PUCO staff recommended the exclusion of $59 million of certain utility investments and $55 million of capitalized incentives from rate base, and a reduction in employee-related expenses of $23 million. In addition, the PUCO staff recommended increases to the DIR revenue cap and ESRR cost cap that were less than OPCo’s requested increases. Responses to the PUCO staff report are due in November 2025 and a hearing is scheduled for January 2026. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters (Applies to AEP and PSO)

2024 Oklahoma Base Rate Case

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

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

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


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SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2020 Texas Base Rate Case

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

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

February 2021 Severe Winter Weather Impacts in SPP

In February 2021, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021 to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are shown in the table below:

JurisdictionSeptember 30, 2025December 31, 2024Approved Recovery PeriodApproved Carrying Charge
(in millions)
Arkansas$25.1 $37.2 6 years(a)
Louisiana47.2 70.6 (b)(b)
Texas49.6 72.7 5 years1.65%
Total$121.9 $180.5 

(a)SWEPCo is permitted to record carrying costs on the unrecovered balance of fuel costs at a weighted-cost of capital approved by the APSC. In August 2024, the APSC issued an order that found SWEPCo had prudently incurred these costs.
(b)In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge equal to the prime rate. The special order states the fuel and purchased power costs incurred will be subject to a future LPSC audit.

If SWEPCo is unable to recover any of the costs relating to the extraordinary fuel and purchases of electricity, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

2025 Arkansas Base Rate Case

In March 2025, SWEPCo filed a request with the APSC for a $114 million annual base rate increase based upon a 10.9% ROE with a capital structure of 52.3% debt and 47.7% common equity. The increase includes the Arkansas jurisdictional share of Diversion and Wagon Wheel wind facilities. SWEPCo is also electing to have its rates regulated under a Formula Rate Review mechanism. In August 2025 and October 2025, APSC staff and intervenors filed testimony recommending an annual base rate increase ranging from $53 million to $99 million with a 9.5% ROE. APSC staff recommended a capital structure of 54.8% debt and 45.2% common equity. APSC staff and certain intervenors recommended recovery of the $37 million Arkansas jurisdictional share of the remaining net book value of the Pirkey Plant over 20 years with no debt or equity return. A hearing is scheduled for November 2025. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

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2025 Texas Base Rate Case

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

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

North Central Wind Energy Facilities (NCWF)

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

FERC Rate Matters

Independence Energy Connection Project (Applies to AEP)

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

In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC had not been canceled and remained necessary to alleviate congestion. In July 2025, PJM removed the IEC from suspended status and indicated the project going forward will be included in PJM’s models with a modified scope. PJM continues to evaluate reliability and market efficiency in the area. As of September 30, 2025, AEP’s share of IEC capital expenditures was approximately $91 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is canceled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


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

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

20212022202320242025Total
(in millions)
$78.3 $68.5 $60.7 $52.1 $48.7 $308.3 

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

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

In June 2025, the FERC issued two orders, partially reversing its January 2024 decisions on the basis of IRS PLRs accepted into the record, and concluding that the accelerated depreciation-related NOLC adjustments should be included in rate base and should also be included in the computation of Excess ADIT regulatory liabilities to be refunded to customers. Requests for rehearing were filed by intervenors in July 2025. As directed by the FERC in its June 2025 order, AEP transmission owning subsidiaries within PJM and SPP submitted compliance filings in August 2025 that revised the March 2024 refund compliance reports and permit the collection of excess refunds provided to customers, with interest, in the annual update for the 2025 rate year. In October 2025, intervenors filed comments in response to the compliance filings associated with the AEP transmission owning subsidiaries within PJM and filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit seeking review of the FERC’s June 2025 order.


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

AEPAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Total Revenues$270.5 $214.3 $5.6 $10.8 $— $6.4 $26.9 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation(23.9)— (17.2)— — — — 
Other Operation53.0 — 14.8 (6.0)0.1 18.8 10.1 
Income (Loss) Before Income Tax Expense (Benefit)241.4214.38.016.8(0.1)(12.4)16.8
Income Tax Expense (Benefit)(312.8)(203.2)(21.4)(27.8)— (15.6)(38.9)
Net Income (Loss)554.2 417.5 29.4 44.6 (0.1)3.2 55.7 
Net Income Attributable to Noncontrolling Interest55.2 55.2 — — — — — 
Earnings (Loss) Attributable to Common Shareholder$499.0 $362.3 $29.4 $44.6 $(0.1)$3.2 $55.7 

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

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

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

In March 2025, the KPSC and the Attorney General of Kentucky filed a complaint at the FERC against AEPSC and the AEP East Companies challenging the manner in which costs are allocated for local transmission projects pursuant to the TA. The complaint contends that certain costs allocated to KPCo are unjust, unreasonable and provide no benefit to KPCo customers. The relief requested in the complaint includes requiring a revision to the TA so that the costs for local transmission projects remain exclusively with the retail distribution service territory where the project is located unless a specific project is granted approval to establish a different cost allocation by the state commissions. Various parties have filed comments and motions to intervene. In May 2025, AEP filed a motion to dismiss and answered the complaint. If the FERC orders a change in the way costs are allocated pursuant to the TA it could impact future net income, cash flows and financial condition.

FERC Audit (Applies to AEP and SWEPCo)

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

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

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

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2024 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit (Applies to AEP)

Standby letters of credit are entered into with third-parties.  These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

AEP has $5 billion and $1 billion revolving credit facilities due in March 2029 and March 2027, respectively. AEP may issue up to $1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of September 30, 2025, no letters of credit were issued under either revolving credit facility.

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility.  AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2025 were as follows:
CompanyAmountMaturity
 (in millions) 
AEP$364.0 October 2025 to September 2026

Indemnifications and Other Guarantees

Contracts

The Registrants enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of September 30, 2025, there were no material liabilities recorded for any indemnifications.

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

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Master Lease Agreements (Applies to all Registrants except AEPTCo)

The Registrants lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed.  As of September 30, 2025, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:
CompanyMaximum
Potential Loss
(in millions)
AEP$37.9 
AEP Texas8.4 
APCo5.3 
I&M3.9 
OPCo6.4 
PSO3.5 
SWEPCo4.4 

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

Federal EPA’s Revised CCR Rule

In April 2024, the Federal EPA finalized revisions to the CCR Rule (Legacy CCR Rule) to expand the scope of the rule to include inactive impoundments at inactive facilities (legacy CCR surface impoundments) as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land (CCR management units). The Federal EPA is requiring that owners and operators of legacy surface impoundments comply with all of the Legacy CCR Rule requirements applicable to inactive CCR surface impoundments at active facilities, except for the location restrictions and liner design criteria. The rule establishes compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within five years after the effective date of the final rule. The rule requires evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. Closure may be accomplished by applying an impermeable cover system over the CCR material (closure in place) or the CCR material may be excavated and placed in a compliant landfill (closure by removal). Groundwater monitoring and other analysis over the next three years will provide additional information on the planned closure method. In the second quarter of 2024, AEP evaluated the applicability of the rule to current and former plant sites and recorded a $674 million increase in ARO, based on initial cost estimates primarily reflecting compliance with the rule through closure in place and future groundwater monitoring requirements pursuant to the Legacy CCR Rule.

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

AEP will seek cost recovery through regulated rates, including proposal of new regulatory mechanisms for cost recovery where existing mechanisms are not applicable. The rule could have an additional, material adverse impact on net income, cash flows and financial condition if AEP cannot ultimately recover these additional costs of compliance. Several parties, including AEP and one of its trade associations, have filed petitions for review of the Legacy CCR Rule with the U.S. Court of Appeals for the D.C. Circuit. One of the parties also filed a motion to stay the Legacy CCR Rule pending the outcome of the litigation. In November 2024, the court denied the stay motion. The litigation is being held in abeyance until December 15, 2025. The Federal EPA informed the court that it has determined it will reconsider the Legacy CCR Rule in whole or in part, but has not yet decided the full scope of reconsideration. The Federal EPA expects to have determined which aspects of the Legacy CCR Rule it will reconsider, in whole or in part, by January 2026. Reconsideration of the rule will require a new round of notice-and-comment rulemaking. In July 2025, the Federal EPA issued a proposed rule to extend certain compliance deadlines for CCR management units under the Legacy CCR Rule. Management cannot predict the outcome of the litigation or any further actions by the Federal EPA related to the rule.

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

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials.  The Registrants currently incur costs to dispose of these substances safely. For remediation processes not specifically discussed, management does not anticipate that the liabilities, if any, arising from such remediation processes would have a material effect on the financial statements.

NUCLEAR CONTINGENCIES (Applies to AEP and I&M)

I&M owns and operates the Cook Plant under licenses granted by the Nuclear Regulatory Commission.  I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. Management has started the application process for license extensions for both units that would extend Unit 1 and Unit 2 to 2054 and 2057, respectively.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

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

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

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

AEP sold the Gavin Power Station to Gavin Power LLC and Lighthouse Generation LLC in 2017. Pursuant to the PSA for that transaction, AEP maintained responsibility to complete closure of the 300 acre unlined fly ash reservoir (FAR) pond in accordance with the closure plan approved by the Ohio EPA and to indemnify the purchasers for that work. In July 2021, closure work was completed by AEP. In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow another pond at the Gavin Power Station, the CCR surface impoundment, to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several assertions related to the CCR Rule, including an assertion that the closure of the FAR is noncompliant with the CCR Rule in multiple respects. The owners of the Gavin Power Station have notified AEP that they believe they are entitled to indemnification for any damages that may result from these claims, including any future enforcement or litigation resulting from any determinations of noncompliance by the Federal EPA with various aspects of the CCR Rule consistent with the Gavin Denial. The owners of the Gavin Power Station have also sought indemnification for landowner claims for property damage allegedly caused by modifications to the FAR. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. In January 2024, Gavin Power LLC filed a complaint with the United States District Court for the Southern District of Ohio, alleging various violations of the Administrative Procedure Act and asserting that the Federal EPA, through its prior inaction, has waived and is estopped from raising certain objections raised in the Gavin Denial. The complaint does not assert any claims against AEP. In August 2025, the District Court dismissed the complaint at the Federal EPA’s request. Based on the information currently available, management does not believe a loss is probable and cannot determine a range of potential losses, if any, that is reasonably possible of occurring.
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6. ACQUISITIONS AND DISPOSITIONS

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

ACQUISITIONS

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

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

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

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


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As of September 30, 2025, PSO expanded its generation portfolio by acquiring four electric generation facilities for a total of $1.7 billion. The table below summarizes the impact at acquisition on PSO’s balance sheets:
Plant NameStateFuel TypeGeneration Capacity
(MWs)		Property, Plant and Equipment, NetOperating Lease AssetsAsset Retirement ObligationsOther Liabilities
(in millions)
Green CountryOKNatural Gas795$818.9 $— $— $91.4 (a)
PixleyKSSolar189379.6 8.9 12.4 — 
Flat Ridge IVKSWind135305.3 7.4 3.1 — 
Flat Ridge VKSWind153319.1 8.8 3.8 — 
Total1,272 $1,822.9 $25.1 $19.3 $91.4 

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

DISPOSITIONS

Noncontrolling Interest in OHTCo and IMTCo (AEP Transmission Holdco Segment) (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. The partnership was structured pursuant to a contribution agreement between AEPTCo, along with Midwest Transmission Holding Company LLC (“Midwest Transmission”), a wholly-owned subsidiary of AEPTCo that owns all the stock of OHTCo and IMTCo, and Olympus BidCo L.P. (“the Investor”), a special purpose entity controlled by (i) investment funds managed by or affiliated with Kohlberg Kravis Roberts & Co. L.P. and (ii) Public Sector Pension Investment Board, whereby the Investor agreed to acquire a 19.9% noncontrolling equity interest in Midwest Transmission for $2.82 billion. The transaction closed in June 2025. AEP received cash proceeds of approximately $2.78 billion, net of transaction costs. Net proceeds are being used to help finance AEP’s capital plan.

Disposition of AEP OnSite Partners (Generation & Marketing Segment) (Applies to AEP)

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

Disposition of NMRD (Generation & Marketing Segment) (Applies to AEP)

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

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

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

Components of Net Periodic Benefit Cost (Credit)

Pension Plans

Three Months Ended September 30, 2025AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$23.9 $2.2 $2.3 $3.2 $2.2 $1.5 $1.9 
Interest Cost52.9 4.4 6.2 6.2 4.9 2.5 3.2 
Expected Return on Plan Assets(70.3)(5.6)(9.4)(9.7)(7.3)(3.8)(3.7)
Amortization of Net Actuarial Loss4.1 0.3 0.5 0.4 0.4 0.3 0.2 
Net Periodic Benefit Cost (Credit)$10.6 $1.3 $(0.4)$0.1 $0.2 $0.5 $1.6 

Three Months Ended September 30, 2024AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$25.6 $2.3 $2.4 $3.3 $2.3 $1.5 $1.9 
Interest Cost51.9 4.4 6.2 5.9 4.8 2.5 3.1 
Expected Return on Plan Assets(80.2)(6.5)(10.7)(10.7)(8.2)(4.3)(4.4)
Amortization of Net Actuarial Loss1.0 — 0.1 0.1 0.1 — 0.1 
Net Periodic Benefit Cost (Credit) (a)$(1.7)$0.2 $(2.0)$(1.4)$(1.0)$(0.3)$0.7 

Nine Months Ended September 30, 2025AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$71.8 $6.6 $6.9 $9.5 $6.8 $4.5 $5.7 
Interest Cost158.5 13.2 18.7 18.6 14.6 7.7 9.4 
Expected Return on Plan Assets(210.8)(16.7)(28.2)(29.1)(22.0)(11.5)(11.0)
Amortization of Net Actuarial Loss12.2 1.0 1.4 1.3 1.1 0.6 0.7 
Net Periodic Benefit Cost (Credit)$31.7 $4.1 $(1.2)$0.3 $0.5 $1.3 $4.8 

Nine Months Ended September 30, 2024AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$76.8 $6.7 $7.3 $9.9 $7.0 $4.6 $5.9 
Interest Cost155.7 13.1 18.6 17.8 14.2 7.5 9.3 
Expected Return on Plan Assets(240.6)(19.5)(32.1)(32.1)(24.5)(13.0)(13.2)
Amortization of Net Actuarial Loss3.2 0.2 0.3 0.3 0.2 0.1 0.2 
Net Periodic Benefit Cost (Credit) (a)$(4.9)$0.5 $(5.9)$(4.1)$(3.1)$(0.8)$2.2 

(a)Excludes an immaterial settlement amount to a non-qualified pension plan in the second quarter of 2024 for AEP. See Note 12 - Voluntary Severance Program for additional information.
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OPEB

Three Months Ended September 30, 2025AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$0.9 $— $— $— $0.1 $0.1 $0.1 
Interest Cost8.5 0.7 1.4 1.0 0.8 0.4 0.5 
Expected Return on Plan Assets(28.2)(2.3)(4.1)(3.4)(2.9)(1.6)(1.9)
Amortization of Prior Service Credit(0.6)— (0.1)— (0.1)— — 
Amortization of Net Actuarial Gain(0.3)— (0.1)— — — — 
Net Periodic Benefit Credit$(19.7)$(1.6)$(2.9)$(2.4)$(2.1)$(1.1)$(1.3)

Three Months Ended September 30, 2024AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$1.1 $— $0.2 $0.1 $— $0.1 $0.1 
Interest Cost10.3 0.9 1.7 1.2 1.1 0.6 0.7 
Expected Return on Plan Assets(27.8)(2.3)(4.1)(3.4)(3.0)(1.5)(1.9)
Amortization of Prior Service Credit(3.1)(0.3)(0.5)(0.4)(0.3)(0.2)(0.3)
Amortization of Net Actuarial Loss0.8 0.1 0.1 0.1 0.1 — 0.1 
Net Periodic Benefit Credit (a)$(18.7)$(1.6)$(2.6)$(2.4)$(2.1)$(1.0)$(1.3)

Nine Months Ended September 30, 2025AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$2.7 $0.2 $0.3 $0.3 $0.3 $0.2 $0.2 
Interest Cost25.7 2.0 4.1 2.9 2.5 1.3 1.6 
Expected Return on Plan Assets(84.7)(7.0)(12.3)(10.1)(8.8)(4.6)(5.7)
Amortization of Prior Service Credit(1.8)(0.1)(0.3)(0.2)(0.2)(0.1)(0.1)
Amortization of Net Actuarial Gain(0.9)— (0.3)— — — — 
Net Periodic Benefit Credit$(59.0)$(4.9)$(8.5)$(7.1)$(6.2)$(3.2)$(4.0)

Nine Months Ended September 30, 2024AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$3.3 $0.2 $0.4 $0.4 $0.2 $0.2 $0.3 
Interest Cost31.4 2.5 5.0 3.6 3.2 1.7 2.0 
Expected Return on Plan Assets(83.5)(6.8)(12.2)(10.1)(8.9)(4.5)(5.6)
Amortization of Prior Service Credit(9.5)(0.8)(1.4)(1.3)(0.9)(0.6)(0.8)
Amortization of Net Actuarial Loss2.3 0.2 0.3 0.3 0.3 0.1 0.2 
Net Periodic Benefit Credit (a)$(56.0)$(4.7)$(7.9)$(7.1)$(6.1)$(3.1)$(3.9)

(a)Excludes an immaterial amount related to special termination benefits resulting from the voluntary severance program announced in the second quarter of 2024. See Note 12 - Voluntary Severance Program for additional information.


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Qualified Pension Contribution (Applies to all Registrants except AEPTCo and OPCo)

For the qualified pension plan, discretionary contributions may be made to maintain the funded status of the plan. In the second quarter of 2025, AEP made a discretionary contribution to the qualified pension plan. The following table provides details of the contribution by Registrant:

CompanyQualified Pension Plan
(in millions)
AEP$94.7 
AEP Texas12.0 
APCo0.4 
I&M2.1 
PSO1.4 
SWEPCo8.8 
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8.  BUSINESS SEGMENTS

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

AEP’s Reportable Segments

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

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

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

Vertically Integrated Utilities

•Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

•Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.
•OPCo purchases energy and capacity to serve standard service offer customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

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

Generation & Marketing

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

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








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The tables below represent AEP’s reportable segment income statement information for the three and nine months ended September 30, 2025 and 2024 and reportable segment balance sheet information as of September 30, 2025 and December 31, 2024. The significant expenses disclosed below align with the segment-level information that is regularly provided to the CODM.

Three Months Ended September 30, 2025
VIUT&DAEPTHCoG&MTotal Reportable SegmentsCorporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions)
Revenues from:
External Customers$3,511.2 $1,680.2 $119.7 $693.8 $6,004.9 $5.5 $— $6,010.4 
Other Operating Segments74.5 9.1 453.5 18.9 556.0 30.4 (586.4)(b)— 
Total Revenues3,585.7 1,689.3 573.2 712.7 6,560.9 35.9 (586.4)6,010.4 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation1,168.4 263.8 — 624.9 2,057.1 — (76.9)1,980.2 
Other Operation and Maintenance998.2 623.5 53.3 35.4 1,710.4 8.1 (515.6)1,202.9 
Depreciation and Amortization547.4 209.8 123.5 3.9 884.6 (5.0)— 879.6 
Taxes Other Than Income Taxes141.6 190.4 87.3 0.7 420.0 0.2 6.1 426.3 
Allowance for Equity Funds Used During Construction19.4 18.3 20.8 — 58.5 — — 58.5 
Interest Expense219.1 106.4 63.3 1.5 390.3 140.2 (22.0)508.5 
Income Tax Expense (Benefit)(25.6)57.2 62.0 15.5 109.1 29.6 — 138.7 
Equity Earnings of Unconsolidated Subsidiaries0.2 0.1 20.8 — 21.1 — — 21.1 
Other Segment Items (c)(22.0)(11.0)25.5 (13.5)(21.0)(19.2)22.0 (18.2)
Earnings (Loss) Attributable to AEP Common Shareholders$578.2 $267.6 $199.9 $44.3 $1,090.0 $(118.0)$— $972.0 
Gross Property Additions$1,203.2 $711.2 $368.0 $3.2 $2,285.6 $18.5 $(25.1)$2,279.0 

Three Months Ended September 30, 2024
VIUT&DAEPTHCoG&MTotal Reportable SegmentsCorporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions)
Revenues from:
External Customers$3,248.8 $1,568.5 $113.1 $483.7 $5,414.1 $6.0 $— $5,420.1 
Other Operating Segments54.2 6.9 399.4 15.4 475.9 32.1 (508.0)(b)— 
Total Revenues3,303.0 1,575.4 512.5 499.1 5,890.0 38.1 (508.0)5,420.1 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation1,100.4 213.2 — 413.6 1,727.2 — (68.0)1,659.2 
Other Operation and Maintenance881.6 599.1 40.0 20.6 1,541.3 53.6 (445.4)1,149.5 
Depreciation and Amortization530.6 212.8 110.5 4.0 857.9 (5.2)— 852.7 
Taxes Other Than Income Taxes138.1 181.6 81.2 0.8 401.7 0.1 5.4 407.2 
Allowance for Equity Funds Used During Construction12.9 17.0 24.3 — 54.2 — — 54.2 
Interest Expense189.9 106.4 56.2 4.0 356.5 168.4 (26.1)498.8 
Income Tax Expense (Benefit)(64.6)49.4 60.9 (23.1)22.6 14.9 — 37.5 
Equity Earnings (Loss) of Unconsolidated Subsidiaries0.4 — 23.0 — 23.4 (6.1)— 17.3 
Other Segment Items (c)(31.2)(15.3)(3.7)(14.1)(64.3)(34.7)26.1 (72.9)
Earnings (Loss) Attributable to AEP Common Shareholders$571.5 $245.2 $214.7 $93.3 $1,124.7 $(165.1)$— $959.6 
Gross Property Additions$809.3 $609.7 $425.8 $13.2 $1,858.0 $7.4 $(15.1)$1,850.3 


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Nine Months Ended September 30, 2025
VIUT&DAEPTHCoG&MTotal Reportable SegmentsCorporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions)
Revenues from:
External Customers$9,531.2 $4,638.3 $390.7 $1,975.4 $16,535.6 $25.1 $— $16,560.7 
Other Operating Segments207.5 27.7 1,481.2 50.4 1,766.8 85.0 (1,851.8)(b)— 
Total Revenues9,738.7 4,666.0 1,871.9 2,025.8 18,302.4 110.1 (1,851.8)16,560.7 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation3,164.3 730.3 — 1,700.8 5,595.4 — (220.9)5,374.5 
Other Operation and Maintenance2,863.4 1,741.7 135.7 65.5 4,806.3 44.4 (1,648.6)3,202.1 
Depreciation and Amortization1,593.9 614.2 360.8 12.3 2,581.2 (15.1)— 2,566.1 
Taxes Other Than Income Taxes398.1 554.9 240.1 1.7 1,194.8 0.8 17.7 1,213.3 
Allowance for Equity Funds Used During Construction51.8 56.4 64.7 — 172.9 — — 172.9 
Interest Expense620.8 318.0 178.9 5.4 1,123.1 438.3 (68.5)1,492.9 
Income Tax Expense (Benefit)(117.2)141.9 (10.4)70.0 84.3 (71.0)— 13.3 
Equity Earnings of Unconsolidated Subsidiaries0.8 1.5 66.5 — 68.8 11.1 — 79.9 
Other Segment Items (c)(67.0)(33.2)85.1 (38.7)(53.8)(61.4)68.5 (46.7)
Earnings (Loss) Attributable to AEP Common Shareholders$1,335.0 $656.1 $1,012.9 $208.8 $3,212.8 $(214.8)$— $2,998.0 
Gross Property Additions$4,356.4 $2,078.9 $1,181.9 $9.9 $7,627.1 $54.3 $(22.9)$7,658.5 

Nine Months Ended September 30, 2024
VIUT&DAEPTHCoG&MTotal Reportable SegmentsCorporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions)
Revenues from:
External Customers$8,722.0 $4,480.5 $332.3 $1,442.1 $14,976.9 $48.1 $— $15,025.0 
Other Operating Segments147.9 21.0 1,167.4 88.0 1,424.3 100.5 (1,524.8)(b)— 
Total Revenues8,869.9 4,501.5 1,499.7 1,530.1 16,401.2 148.6 (1,524.8)15,025.0 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation2,970.3 729.0 — 1,151.0 4,850.3 — (246.8)4,603.5 
Other Operation and Maintenance2,720.1 1,639.0 122.8 94.5 4,576.4 114.6 (1,292.9)3,398.1 
Asset Impairments and Other Related Charges13.4 52.9 — 76.2 142.5 — — 142.5 
Depreciation and Amortization1,470.4 662.2 327.5 17.3 2,477.4 (15.7)— 2,461.7 
Taxes Other Than Income Taxes410.7 550.4 233.4 1.5 1,196.0 0.3 14.9 1,211.2 
Allowance for Equity Funds Used During Construction37.4 50.9 64.7 — 153.0 — — 153.0 
Interest Expense537.3 298.4 166.4 14.9 1,017.0 479.5 (96.5)1,400.0 
Income Tax Expense (Benefit)(324.5)116.3 172.2 (4.3)(40.3)(57.4)— (97.7)
Equity Earnings (Loss) of Unconsolidated Subsidiaries1.1 (0.8)72.6 0.9 73.8 (6.8)— 67.0 
Other Segment Items (c)(87.3)(38.9)(9.4)(46.2)(181.8)(92.0)96.5 (177.3)
Earnings (Loss) Attributable to AEP Common Shareholders$1,198.0 $542.3 $624.1 $226.1 $2,590.5 $(287.5)$— $2,303.0 
Gross Property Additions$2,290.2 $1,730.8 $1,120.4 $33.2 $5,174.6 $16.9 $(22.9)$5,168.6 

145

September 30, 2025
VIUT&DAEPTHCoG&MTotal Reportable SegmentsCorporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions)
Total Assets$59,005.8 $28,429.9 $18,918.9 $1,899.7 $108,254.3 $6,172.3 (d)$(4,173.1)(e)$110,253.5 
Investments in Equity Method Investees$8.8 $3.6 $1,057.9 $— $1,070.3 $165.5 $— $1,235.8 

December 31, 2024
VIUT&DAEPTHCoG&MTotal Reportable SegmentsCorporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions)
Total Assets$54,996.5 $26,864.3 $18,011.9 $1,633.9 $101,506.6 $5,550.8 (d)$(3,979.4)(e)$103,078.0 
Investments in Equity Method Investees$9.1 $2.0 $996.1 $— $1,007.2 $48.7 $— $1,055.9 

(a)Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, income tax expense and other nonallocated costs.
(b)Represents intersegment revenues.
(c)Other segment items included in segment earnings (loss) attributable to AEP common shareholders primarily includes Interest and Dividend Income, Non-Service Cost Components of Net Period Benefit Cost and Net Income (Loss) Attributable to Noncontrolling Interests.
(d)Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.
(e)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.

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

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

AEPTCo’s Reportable Segments

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

The CODM of AEPTCo is the AEP President and CEO, who makes operating decisions, allocates resources to and assesses performance based on these operating segments. The CODM uses earnings (loss) attributable to AEPTCo common shareholders (presented on a GAAP basis) as a measure of segment profit or loss in making these decisions. Earnings (loss) attributable to AEPTCo common shareholders includes intercompany revenues and expenses that are eliminated on the consolidated financial statements. The State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one reportable segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities.
146

The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2025 and 2024 and reportable segment balance sheet information as of September 30, 2025 and December 31, 2024. The significant expenses disclosed below align with the segment-level information that is regularly provided to the CODM.

Three Months Ended September 30, 2025
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
$107.9 $— $— $107.9 
Sales to AEP Affiliates
450.1 — — 450.1 
Total Revenues558.0 — — 558.0 
Other Operation and Maintenance49.8 0.1 — 49.9 
Depreciation and Amortization
121.3 — — 121.3 
Taxes Other Than Income Taxes85.9 — — 85.9 
Interest Income
0.8 65.5 (65.0)(a)1.3 
Allowance for Equity Funds Used During Construction 20.8 — — 20.8 
Interest Expense 61.2 65.1 (65.0)(a)61.3 
Income Tax Expense56.1 0.1 — 56.2 
Other Segment Items (b)— 26.6 — 26.6 
Earnings (Loss) Attributable to AEPTCo Common Shareholders$205.3 $(26.4)(c)$— $178.9 
Gross Property Additions$357.8 $— $— $357.8 

Three Months Ended September 30, 2024
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
$101.1 $— $— $101.1 
Sales to AEP Affiliates
395.9 — — 395.9 
Other Revenues
0.2 — — 0.2 
Total Revenues497.2 — — 497.2 
Other Operation and Maintenance37.3 0.1 — 37.4 
Depreciation and Amortization
108.2 — — 108.2 
Taxes Other Than Income Taxes79.7 — — 79.7 
Interest Income
2.3 61.7 (60.9)(a)3.1 
Allowance for Equity Funds Used During Construction 24.3 — — 24.3 
Interest Expense 54.2 61.0 (60.9)(a)54.3 
Income Tax Expense53.6 0.1 — 53.7 
Earnings Attributable to AEPTCo Common Shareholders$190.8 $0.5 (c)$— $191.3 
Gross Property Additions$385.1 $— $— $385.1 

147

Nine Months Ended September 30, 2025
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
$356.8 $— $— $356.8 
Sales to AEP Affiliates
1,470.0 — — 1,470.0 
Other Revenues
0.1 — — 0.1 
Total Revenues1,826.9 — — 1,826.9 
Other Operation and Maintenance126.2 0.3 — 126.5 
Depreciation and Amortization
354.3 — — 354.3 
Taxes Other Than Income Taxes235.8 — — 235.8 
Interest Income
1.8 238.8 (237.5)(a)3.1 
Allowance for Equity Funds Used During Construction 64.7 — — 64.7 
Interest Expense 222.7 187.7 (237.5)(a)172.9 
Income Tax Expense (Benefit)(39.1)10.8 — (28.3)
Other Segment Items (b)— 87.3 — 87.3 
Earnings (Loss) Attributable to AEPTCo Common Shareholders$993.5 $(47.3)(c)$— $946.2 
Gross Property Additions$1,144.7 $— $— $1,144.7 

Nine Months Ended September 30, 2024
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
$295.1 $— $— $295.1 
Sales to AEP Affiliates
1,157.1 — — 1,157.1 
Other Revenues
3.0 — — 3.0 
Total Revenues1,455.2 — — 1,455.2 
Other Operation and Maintenance115.9 1.7 — 117.6 
Depreciation and Amortization
320.8 — — 320.8 
Taxes Other Than Income Taxes228.6 — — 228.6 
Interest Income
6.8 180.5 (178.0)(a)9.3 
Allowance for Equity Funds Used During Construction 64.7 — — 64.7 
Interest Expense 160.3 178.2 (178.0)(a)160.5 
Income Tax Expense153.4 0.1 — 153.5 
Earnings Attributable to AEPTCo Common Shareholders$547.7 $0.5 (c)$— $548.2 
Gross Property Additions$1,042.9 $— $— $1,042.9 

September 30, 2025
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Assets $17,222.2 $6,396.4 (d)$(6,410.0)(e)$17,208.6 

December 31, 2024
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Assets $16,887.7 $8,670.4 (d)$(9,187.8)(e)$16,370.3 

(a)Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
(b)Other segment items included in segment earnings (loss) attributable to AEPTCo common shareholders primarily includes Net Income (Loss) Attributable to Noncontrolling Interests.
(c)Includes elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(d)Primarily relates to Notes Receivable from the State Transcos.
(e)Primarily relates to elimination of Notes Receivable from the State Transcos.
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9.  DERIVATIVES AND HEDGING

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

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

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

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

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

The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the AEP Board.

The following table represents the gross notional volume of the Registrants’ outstanding derivative contracts:
Notional Volume of Derivative Instruments
September 30, 2025December 31, 2024
Primary Risk
Exposure		AEPAEP TexasAPCoI&MOPCoPSOSWEPCoAEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Commodity:     
Power (MWhs)327.3 — 37.9 11.7 1.8 11.3 9.4 282.4 — 23.6 7.7 2.0 5.0 4.6 
Natural Gas (MMBtus)168.5 — 46.8 — — 42.0 19.2 152.8 — 42.2 — — 46.2 15.4 
Heating Oil and Gasoline (Gallons)7.5 2.1 0.9 1.4 1.1 0.7 0.9 7.9 2.0 0.9 2.0 1.1 0.7 0.9 
Interest Rate (USD)$39.5 $— $— $— $— $— $— $59.3 $— $— $— $— $— $— 
Interest Rate on Long-term Debt (USD)$950.0 $— $— $— $— $— $— $950.0 $— $— $— $— $— $— 
149

Fair Value Hedging Strategies (Applies to AEP)

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

Cash Flow Hedging Strategies

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

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

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

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

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

According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $71 million and $87 million as of September 30, 2025 and December 31, 2024, respectively. There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of September 30, 2025 and December 31, 2024. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was not material for the Registrants as of September 30, 2025 and December 31, 2024.
150

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

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

September 30, 2025
AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
Assets:(in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity$654.2 $0.1 $94.4 $19.6 $— $68.6 $59.6 
Hedging Contracts - Commodity54.4 — — — — — — 
Total Current Risk Management Assets708.6 0.1 94.4 19.6 — 68.6 59.6 
Long-term Risk Management Assets
Risk Management Contracts - Commodity445.0 — 2.5 1.4 — — 0.2 
Hedging Contracts - Commodity65.1 — — — — — — 
Total Long-term Risk Management Assets510.1 — 2.5 1.4 — — 0.2 
Total Assets$1,218.7 $0.1 $96.9 $21.0 $— $68.6 $59.8 
Liabilities:
Current Risk Management Liabilities
Risk Management Contracts - Commodity$360.8 $— $5.0 $11.8 $6.3 $16.4 $6.2 
Hedging Contracts - Commodity15.7 — — — — — — 
Hedging Contracts - Interest Rate27.4 — — — — — — 
Total Current Risk Management Liabilities403.9 — 5.0 11.8 6.3 16.4 6.2 
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity359.3 — 0.5 1.6 38.0 1.4 1.2 
Hedging Contracts - Commodity6.5 — — — — — — 
Hedging Contracts - Interest Rate21.6 — — — — — — 
Total Long-term Risk Management Liabilities387.4 — 0.5 1.6 38.0 1.4 1.2 
Total Liabilities$791.3 $— $5.5 $13.4 $44.3 $17.8 $7.4 
Total MTM Derivative Contract Net Assets (Liabilities) Recognized$427.4 $0.1 $91.4 $7.6 $(44.3)$50.8 $52.4 
151

December 31, 2024
AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
Assets:(in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity$425.0 $— $40.2 $28.5 $— $22.3 $19.1 
Hedging Contracts - Commodity54.1 — — — — — — 
Total Current Risk Management Assets479.1 — 40.2 28.5 — 22.3 19.1 
Long-term Risk Management Assets
Risk Management Contracts - Commodity475.4 — 2.0 1.2 — 1.6 — 
Hedging Contracts - Commodity84.6 — — — — — — 
Total Long-term Risk Management Assets560.0 — 2.0 1.2 — 1.6 — 
Total Assets$1,039.1 $— $42.2 $29.7 $— $23.9 $19.1 
Liabilities:
Current Risk Management Liabilities
Risk Management Contracts - Commodity$304.1 $0.3 $6.6 $10.5 $7.5 $7.6 $3.4 
Hedging Contracts - Commodity11.3 — — — — — — 
Hedging Contracts - Interest Rate36.3 — — — — — — 
Total Current Risk Management Liabilities351.7 0.3 6.6 10.5 7.5 7.6 3.4 
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity390.7 — 0.8 2.1 40.2 0.2 — 
Hedging Contracts - Commodity2.7 — — — — — — 
Hedging Contracts - Interest Rate35.3 — — — — — — 
Total Long-term Risk Management Liabilities428.7 — 0.8 2.1 40.2 0.2 — 
Total Liabilities$780.4 $0.3 $7.4 $12.6 $47.7 $7.8 $3.4 
Total MTM Derivative Contract Net Assets (Liabilities) Recognized$258.7 $(0.3)$34.8 $17.1 $(47.7)$16.1 $15.7 



152

Offsetting Assets and Liabilities

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

September 30, 2025
AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
Assets:(in millions)
Current Risk Management Assets
Gross Amounts Recognized$708.6 $0.1 $94.4 $19.6 $— $68.6 $59.6 
Gross Amounts Offset(300.7)— (2.4)(8.7)— (0.5)(1.8)
Net Amounts Presented407.9 0.1 92.0 10.9 — 68.1 57.8 
Long-term Risk Management Assets
Gross Amounts Recognized510.1 — 2.5 1.4 — — 0.2 
Gross Amounts Offset(245.5)— (0.4)(1.4)— — (0.2)
Net Amounts Presented264.6 — 2.1 — — — — 
Total Assets$672.5 $0.1 $94.1 $10.9 $— $68.1 $57.8 
Liabilities:
Current Risk Management Liabilities
Gross Amounts Recognized$403.9 $— $5.0 $11.8 $6.3 $16.4 $6.2 
Gross Amounts Offset(281.2)— (2.4)(11.0)— (0.5)(1.8)
Net Amounts Presented122.7 — 2.6 0.8 6.3 15.9 4.4 
Long-term Risk Management Liabilities
Gross Amounts Recognized387.4 — 0.5 1.6 38.0 1.4 1.2 
Gross Amounts Offset(200.5)— (0.4)(1.4)— — (0.2)
Net Amounts Presented186.9 — 0.1 0.2 38.0 1.4 1.0 
Total Liabilities$309.6 $— $2.7 $1.0 $44.3 $17.3 $5.4 
Total MTM Derivative Contract Net Assets (Liabilities)$362.9 $0.1 $91.4 $9.9 $(44.3)$50.8 $52.4 

December 31, 2024
AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
Assets:(in millions)
Current Risk Management Assets
Gross Amounts Recognized$479.1 $— $40.2 $28.5 $— $22.3 $19.1 
Gross Amounts Offset(268.7)— (4.5)(10.1)— (1.7)(1.0)
Net Amounts Presented210.4 — 35.7 18.4 — 20.6 18.1 
Long-term Risk Management Assets
Gross Amounts Recognized560.0 — 2.0 1.2 — 1.6 — 
Gross Amounts Offset(270.9)— (0.6)(1.2)— (0.2)— 
Net Amounts Presented289.1 — 1.4 — — 1.4 — 
Total Assets$499.5 $— $37.1 $18.4 $— $22.0 $18.1 
Liabilities:
Current Risk Management Liabilities
Gross Amounts Recognized$351.7 $0.3 $6.6 $10.5 $7.5 $7.6 $3.4 
Gross Amounts Offset(251.7)(0.3)(4.6)(10.2)(0.2)(1.8)(1.1)
Net Amounts Presented100.0 — 2.0 0.3 7.3 5.8 2.3 
Long-term Risk Management Liabilities
Gross Amounts Recognized428.7 — 0.8 2.1 40.2 0.2 — 
Gross Amounts Offset(204.3)— (0.6)(1.7)— (0.2)— 
Net Amounts Presented224.4 — 0.2 0.4 40.2 — — 
Total Liabilities$324.4 $— $2.2 $0.7 $47.5 $5.8 $2.3 
Total MTM Derivative Contract Net Assets (Liabilities)$175.1 $— $34.9 $17.7 $(47.5)$16.2 $15.8 

153

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

Amount of Gain (Loss) Recognized on Risk Management Contracts

Three Months Ended September 30, 2025
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$5.9 $— $— $— $— $— $— 
Generation & Marketing Revenues11.1 — — — — — — 
Electric Generation, Transmission and Distribution Revenues— — — 5.8 — — — 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation0.8 — 0.8 — — — — 
Other Operation— — — — — — — 
Maintenance— — (0.1)— (0.1)— — 
Regulatory Assets (a)(3.9)0.1 0.2 1.0 3.7 (11.8)3.1 
Regulatory Liabilities (a)58.8 — 17.9 6.5 0.7 17.1 11.8 
Total Gain (Loss) on Risk Management Contracts$72.7 $0.1 $18.8 $13.3 $4.3 $5.3 $14.9 

Three Months Ended September 30, 2024
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$(1.1)$— $— $— $— $— $— 
Generation & Marketing Revenues(67.1)— — — — — — 
Electric Generation, Transmission and Distribution Revenues— — 0.1 (1.2)— — — 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation0.7 — 0.5 — — — — 
Other Operation(0.3)(0.1)— (0.1)— — — 
Maintenance(0.5)(0.1)(0.1)(0.1)(0.1)— (0.1)
Regulatory Assets (a)3.1 (0.6)(3.9)— (9.2)11.6 6.5 
Regulatory Liabilities (a)60.8 — 9.8 2.9 — 23.8 21.8 
Total Gain (Loss) on Risk Management Contracts$(4.4)$(0.8)$6.4 $1.5 $(9.3)$35.4 $28.2 

154

Nine Months Ended September 30, 2025
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$(14.3)$— $— $— $— $— $— 
Generation & Marketing Revenues71.3 — — — — — — 
Electric Generation, Transmission and Distribution Revenues— — 0.3 (14.7)— — — 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation4.6 — 4.6 — — — — 
Other Operation(0.2)(0.1)— — — — — 
Maintenance(0.4)(0.1)(0.1)— (0.1)— (0.1)
Regulatory Assets (a)(8.4)0.3 0.2 — 3.4 (13.6)1.2 
Regulatory Liabilities (a)283.3 — 77.4 21.3 0.9 84.1 82.5 
Total Gain on Risk Management Contracts$335.9 $0.1 $82.4 $6.6 $4.2 $70.5 $83.6 
Nine Months Ended September 30, 2024
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$(22.5)$— $— $— $— $— $— 
Generation & Marketing Revenues(164.8)— — — — — — 
Electric Generation, Transmission and Distribution Revenues— — 0.2 (22.7)— — — 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation2.4 — 2.1 0.1 — — — 
Maintenance0.1 — — — — — — 
Regulatory Assets (a)48.3 (0.3)11.2 3.0 (3.7)19.3 11.6 
Regulatory Liabilities (a)206.0 — 35.5 12.2 — 75.9 71.4 
Total Gain (Loss) on Risk Management Contracts$69.5 $(0.3)$49.0 $(7.4)$(3.7)$95.2 $83.0 

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

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

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

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same line item on the statements of income as that of the associated risk being hedged. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
155

Accounting for Fair Value Hedging Strategies (Applies to AEP)

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

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

The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:
Carrying Amount of the Hedged LiabilitiesCumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
September 30, 2025December 31, 2024September 30, 2025December 31, 2024
(in millions)
Long-term Debt (a) (b)$(916.4)$(898.6)$32.5 $49.3 

(a)Amounts included within Noncurrent Liabilities line item Long-term Debt and Current Liabilities line item Long-term Debt Due Within One Year on the balance sheet.
(b)Amounts include $(16) million and $(22) million as of September 30, 2025 and December 31, 2024, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.

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

Three Months Ended September 30,Nine Months Ended September 30,
2025202420252024
(in millions)
Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a)$(1.1)$14.8 $22.6 $16.7 
Fair Value Portion of Long-term Debt (a)1.1 (14.8)(22.6)(16.7)

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

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

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

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity, Fuel and Other Consumables Used for Electric Generation on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2025 and 2024, AEP applied cash flow hedging to outstanding power derivatives and the Registrant Subsidiaries did not.

The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2025, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives. During the three months ended September 30, 2024, AEP and PSO applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the nine months ended September 30, 2024, AEP, AEP Texas and PSO applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not.

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.
156

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were:
Impact of Cash Flow Hedges on the Registrants’ Balance Sheets
September 30, 2025December 31, 2024
Portion Expected toPortion Expected to
AOCIbe Reclassed toAOCIbe Reclassed to
Gain (Loss)Net Income DuringGain (Loss)Net Income During
Net of Taxthe Next Twelve MonthsNet of Taxthe Next Twelve Months
CommodityInterest RateCommodityInterest RateCommodityInterest RateCommodityInterest Rate
(in millions)
AEP$76.9 $(0.6)$30.6 $0.1 $98.5 $3.3 $33.9 $2.8 
AEP Texas— 5.8 — 0.7 — 6.3 — 0.7 
APCo— 4.5 — 0.8 — 5.1 — 0.8 
I&M— (4.8)— (0.4)— (5.1)— (0.4)
PSO— 2.3 — 0.2 — 3.6 — 0.2 
SWEPCo— 0.8 — 0.3 — 1.0 — 0.3 

As of September 30, 2025, the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is approximately 10 years.

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

Credit Risk

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

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

Credit-Risk-Related Contingent Features

Credit Downgrade Triggers (Applies to AEP)

A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts.  The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral.  The total exposure of AEP’s derivative contracts with collateral triggering events in a net liability position was immaterial as of September 30, 2025 and December 31, 2024. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of September 30, 2025 and December 31, 2024.

157

Cross-Acceleration Triggers (Applies to AEP)

Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by the Registrants under any of their outstanding debt of at least $50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. AEP had derivative contracts with cross-acceleration provisions in a net liability position of $49 million and $72 million and no cash collateral posted as of September 30, 2025 and December 31, 2024, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. The Registrant Subsidiaries had no derivative contracts with cross-acceleration provisions in a net liability position as of September 30, 2025 and December 31, 2024.

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

In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. AEP had derivative contracts with cross-default provisions in a net liability position of $161 million and $164 million and no cash collateral posted as of September 30, 2025 and December 31, 2024, respectively, after considering contractual netting arrangements. If a cross-default provision would have been triggered, settlement at fair value would have been required. APCo, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $2 million, $15 million and $4 million, respectively, and no cash collateral posted as of September 30, 2025. APCo, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $1 million, $4 million and $2 million, respectively, and no cash collateral posted as of December 31, 2024. The other Registrant Subsidiaries had no derivative contracts with cross-default provisions in a net liability position as of September 30, 2025 and December 31, 2024.
158

10.  FAIR VALUE MEASUREMENTS

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

Fair Value Hierarchy and Valuation Techniques

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

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

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

Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities.  They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities.  Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.


159

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

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

The book values and fair values of Long-term Debt are summarized in the following table:
September 30, 2025December 31, 2024
CompanyBook ValueFair ValueBook ValueFair Value
(in millions)
AEP$46,137.6 $43,486.2 $42,642.8 $38,964.7 
AEP Texas7,264.5 6,884.4 6,441.6 5,831.4 
AEPTCo6,240.4 5,515.5 5,768.1 4,853.1 
APCo5,758.1 5,647.6 5,660.3 5,346.0 
I&M3,485.1 3,250.1 3,494.3 3,153.8 
OPCo3,717.8 3,356.7 3,715.7 3,203.4 
PSO3,524.6 3,365.0 2,855.6 2,562.1 
SWEPCo3,972.6 3,626.6 3,980.8 3,431.5 

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

Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS.

The following is a summary of Other Temporary Investments and Restricted Cash:
September 30, 2025
GrossGross
UnrealizedUnrealizedFair
Other Temporary Investments and Restricted CashCostGainsLossesValue
(in millions)
Restricted Cash (a)$39.1 $— $— $39.1 
Other Cash Deposits12.2 — — 12.2 
Fixed Income Securities – Mutual Funds (b)173.3 — (2.2)171.1 
Equity Securities – Mutual Funds14.1 28.0 — 42.1 
Total Other Temporary Investments and Restricted Cash$238.7 $28.0 $(2.2)$264.5 
December 31, 2024
GrossGross
UnrealizedUnrealizedFair
Other Temporary Investments and Restricted CashCostGainsLossesValue
(in millions)
Restricted Cash (a)$43.1 $— $— $43.1 
Other Cash Deposits13.9 — — 13.9 
Fixed Income Securities – Mutual Funds (b)167.2 — (5.3)161.9 
Equity Securities – Mutual Funds12.7 26.9 — 39.6 
Total Other Temporary Investments and Restricted Cash$236.9 $26.9 $(5.3)$258.5 

(a)Primarily represents amounts held for the repayment of debt.
(b)Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
160

The following table provides the activity for fixed income and equity securities within Other Temporary Investments:
 Three Months Ended September 30,Nine Months Ended September 30,
 2025202420252024
(in millions)
Proceeds from Investment Sales$0.4 $4.5 $17.0 $7.5 
Purchases of Investments14.0 6.0 20.5 9.0 
Gross Realized Gains on Investment Sales— 0.4 4.2 0.7 
Gross Realized Losses on Investment Sales— 0.3 0.5 0.5 

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

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

•Acceptable investments (rated investment grade or above when purchased).
•Maximum percentage invested in a specific type of investment.
•Prohibition of investment in obligations of AEP, I&M or their affiliates.
•Withdrawals permitted only for payment of decommissioning costs and trust expenses.

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

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

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

The following is a summary of nuclear trust fund investments:
 September 30, 2025December 31, 2024
GrossGrossOther-Than-GrossGrossOther-Than-
FairUnrealizedUnrealizedTemporaryFairUnrealizedUnrealizedTemporary
ValueGainsLossesImpairmentsValueGainsLossesImpairments
(in millions)
Cash and Cash Equivalents$25.0 $— $— $— $23.3 $— $— $— 
Fixed Income Securities:
United States Government1,385.1 23.0 (0.3)(15.5)1,322.8 8.2 (5.3)(20.2)
Corporate Debt352.9 6.0 (6.8)(7.1)211.3 0.7 (9.8)(5.8)
Subtotal Fixed Income Securities1,738.0 29.0 (7.1)(22.6)1,534.1 8.9 (15.1)(26.0)
Equity Securities - Domestic (a)3,095.9 2,560.0 (0.2)— 2,837.7 2,288.9 (0.4)— 
Spent Nuclear Fuel and Decommissioning Trusts$4,858.9 $2,589.0 $(7.3)$(22.6)$4,395.1 $2,297.8 $(15.5)$(26.0)

(a) Due to the adoption of ASU 2016-1, Other-Than-Temporary Impairments are no longer applicable to Equity Securities with readily determinable fair values.
161

The following table provides the securities activity within the decommissioning and SNF trusts:
Three Months Ended September 30,Nine Months Ended September 30,
 2025202420252024
 (in millions)
Proceeds from Investment Sales$1,037.8 $1,181.9 $2,332.2 $2,336.0 
Purchases of Investments1,056.5 1,201.9 2,386.5 2,389.0 
Gross Realized Gains on Investment Sales112.5 108.4 116.8 118.7 
Gross Realized Losses on Investment Sales1.5 0.7 4.0 6.1 

The base cost of fixed income securities was $1.7 billion and $1.5 billion as of September 30, 2025 and December 31, 2024, respectively.  The base cost of equity securities was $536 million and $549 million as of September 30, 2025 and December 31, 2024, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2025 was as follows:
Fair Value of Fixed
Income Securities
(in millions)
Within 1 year$366.1 
After 1 year through 5 years736.7 
After 5 years through 10 years209.0 
After 10 years426.2 
Total$1,738.0 

162

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2025
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash$25.9 $— $— $13.2 $39.1 
Other Cash Deposits (a)— — — 12.2 12.2 
Fixed Income Securities – Mutual Funds171.1 — — — 171.1 
Equity Securities – Mutual Funds (b)42.1 — — — 42.1 
Total Other Temporary Investments and Restricted Cash239.1 — — 25.4 264.5 
Risk Management Assets
Risk Management Commodity Contracts (c) (d)3.6 623.0 458.7 (517.0)568.3 
Cash Flow Hedges:
Commodity Hedges (c)— 101.0 18.0 (14.8)104.2 
Total Risk Management Assets3.6 724.0 476.7 (531.8)672.5 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)10.7 — — 14.3 25.0 
Fixed Income Securities:
United States Government— 1,385.1 — — 1,385.1 
Corporate Debt— 352.9 — — 352.9 
Subtotal Fixed Income Securities— 1,738.0 — — 1,738.0 
Equity Securities – Domestic (b)3,095.9 — — — 3,095.9 
Total Spent Nuclear Fuel and Decommissioning Trusts3,106.6 1,738.0 — 14.3 4,858.9 
Total Assets$3,349.3 $2,462.0 $476.7 $(492.1)$5,795.9 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)$5.3 $552.4 $148.6 $(452.5)$253.8 
Cash Flow Hedges:
Commodity Hedges (c)— 20.7 1.0 (14.8)6.9 
Fair Value Hedges— 48.9 — — 48.9 
Total Risk Management Liabilities$5.3 $622.0 $149.6 $(467.3)$309.6 
163

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2024
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash$43.1 $— $— $— $43.1 
Other Cash Deposits (a)— — — 13.9 13.9 
Fixed Income Securities – Mutual Funds161.9 — — — 161.9 
Equity Securities – Mutual Funds (b)39.6 — — — 39.6 
Total Other Temporary Investments and Restricted Cash244.6 — — 13.9 258.5 
Risk Management Assets
Risk Management Commodity Contracts (c) (f)2.9 597.3 291.6 (517.2)374.6 
Cash Flow Hedges:
Commodity Hedges (c)— 115.6 21.9 (12.6)124.9 
Total Risk Management Assets2.9 712.9 313.5 (529.8)499.5 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)9.6 — — 13.7 23.3 
Fixed Income Securities:
United States Government— 1,322.8 — — 1,322.8 
Corporate Debt— 211.3 — — 211.3 
Subtotal Fixed Income Securities— 1,534.1 — — 1,534.1 
Equity Securities – Domestic (b)2,837.7 — — — 2,837.7 
Total Spent Nuclear Fuel and Decommissioning Trusts2,847.3 1,534.1 — 13.7 4,395.1 
Total Assets$3,094.8 $2,247.0 $313.5 $(502.2)$5,153.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)$4.4 $534.1 $147.7 $(433.6)$252.6 
Cash Flow Hedges:
Commodity Hedges (c)— 12.6 0.2 (12.6)0.2 
Fair Value Hedges— 71.6 — — 71.6 
Total Risk Management Liabilities$4.4 $618.3 $147.9 $(446.2)$324.4 

164

AEP Texas
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2025
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$7.3 $— $— $— $7.3 
Risk Management Assets     
Risk Management Commodity Contracts (c)— 0.1 — — 0.1 
Total Assets$7.3 $0.1 $— $— $7.4 

December 31, 2024
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$23.5 $— $— $— $23.5 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $0.3 $— $(0.3)$— 

165

APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2025
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$10.8 $— $— $— $10.8 
Risk Management Assets
Risk Management Commodity Contracts (c)— 5.3 91.4 (2.6)94.1 
Total Assets$10.8 $5.3 $91.4 $(2.6)$104.9 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $5.2 $0.1 $(2.6)$2.7 



December 31, 2024
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$16.2 $— $— $— $16.2 
Risk Management Assets
Risk Management Commodity Contracts (c)— 6.5 35.2 (4.6)37.1 
Total Assets$16.2 $6.5 $35.2 $(4.6)$53.3 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $6.9 $— $(4.7)$2.2 

166

I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2025
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)$— $8.5 $11.3 $(8.9)$10.9 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)10.7 — — 14.3 25.0 
Fixed Income Securities:
United States Government— 1,385.1 — — 1,385.1 
Corporate Debt— 352.9 — — 352.9 
Subtotal Fixed Income Securities— 1,738.0 — — 1,738.0 
Equity Securities - Domestic (b)3,095.9 — — — 3,095.9 
Total Spent Nuclear Fuel and Decommissioning Trusts3,106.6 1,738.0 — 14.3 4,858.9 
Total Assets$3,106.6 $1,746.5 $11.3 $5.4 $4,869.8 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $11.8 $0.4 $(11.2)$1.0 

December 31, 2024
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)$— $19.9 $6.9 $(8.4)$18.4 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)9.6 — — 13.7 23.3 
Fixed Income Securities:
United States Government— 1,322.8 — — 1,322.8 
Corporate Debt— 211.3 — — 211.3 
Subtotal Fixed Income Securities— 1,534.1 — — 1,534.1 
Equity Securities - Domestic (b)2,837.7 — — — 2,837.7 
Total Spent Nuclear Fuel and Decommissioning Trusts2,847.3 1,534.1 — 13.7 4,395.1 
Total Assets$2,847.3 $1,554.0 $6.9 $5.3 $4,413.5 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $9.2 $0.5 $(9.0)$0.7 
167

OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2025
Level 1Level 2Level 3OtherTotal
Liabilities:(in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $— $44.3 $— $44.3 

December 31, 2024
Level 1Level 2Level 3OtherTotal
Liabilities:(in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $0.2 $47.5 $(0.2)$47.5 

PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2025
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)$— $0.3 $68.3 $(0.5)$68.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $14.8 $3.0 $(0.5)$17.3 

December 31, 2024
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)$— $3.1 $20.8 $(1.9)$22.0 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $7.0 $0.8 $(2.0)$5.8 
168

SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2025
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$7.8 $— $— $— $7.8 
Risk Management Assets
Risk Management Commodity Contracts (c)— 0.3 59.4 (1.9)57.8 
Total Assets$7.8 $0.3 $59.4 $(1.9)$65.6 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $4.5 $2.8 $(1.9)$5.4 

December 31, 2024
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$3.4 $— $— $— $3.4 
Risk Management Assets
Risk Management Commodity Contracts (c)— 1.0 18.1 (1.0)18.1 
Total Assets$3.4 $1.0 $18.1 $(1.0)$21.5 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $2.8 $0.6 $(1.1)$2.3 

(a)Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third-parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b)Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’
(d)The September 30, 2025 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(1) million in 2025 and $(1) million in periods 2026-2028; Level 2 matures $2 million in 2025, $63 million in periods 2026-2028 and $6 million in periods 2029-2030; Level 3 matures $95 million in 2025, $222 million in periods 2026-2028, $15 million in periods 2029-2030 and $(22) million in periods 2031-2034.  Risk management commodity contracts are substantially comprised of power contracts.
(e)Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(f)The December 31, 2024 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(1) million in 2025; Level 2 matures $16 million in 2025, $43 million in periods 2026-2028, $4 million in periods 2029-2030; Level 3 matures $106 million in 2025, $45 million in periods 2026-2028, $9 million in periods 2029-2030 and $(16) million in periods 2031-2034.  Risk management commodity contracts are substantially comprised of power contracts.

169

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:
Three Months Ended September 30, 2025AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of June 30, 2025$382.8 $108.3 $12.3 $(47.7)$96.9 $69.1 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
44.7 15.6 3.6 (0.1)14.1 9.6 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
13.2 — — — — — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
1.5 — — — — — 
Settlements(131.6)(34.4)(7.1)1.0 (45.2)(29.9)
Transfers into Level 3 (d) (e)7.1 — — — — — 
Transfers out of Level 3 (e)(5.2)— — — — — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
14.6 1.8 2.1 2.5 (0.5)7.8 
Balance as of September 30, 2025$327.1 $91.3 $10.9 $(44.3)$65.3 $56.6 

Three Months Ended September 30, 2024AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of June 30, 2024$288.2 $67.8 $14.5 $(43.2)$49.4 $38.1 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
60.4 13.4 2.9 (0.1)23.2 21.2 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
(6.9)— — — — — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
(0.1)— — — — — 
Settlements(133.1)(26.9)(7.9)1.0 (46.3)(37.7)
Transfers into Level 3 (d) (e)(0.3)— — — — — 
Transfers out of Level 3 (e)(0.6)— — — — — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
(14.5)(7.1)(0.2)(9.3)2.1 2.1 
Balance as of September 30, 2024$193.1 $47.2 $9.3 $(51.6)$28.4 $23.7 
170

Nine Months Ended September 30, 2025AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of December 31, 2024$165.6 $35.2 $6.4 $(47.5)$20.0 $17.5 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
155.3 49.4 12.9 — 37.9 42.2 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
31.1 — — — — — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)14.0 — — — — — 
Settlements(276.9)(84.6)(19.2)5.3 (57.9)(59.7)
Transfers into Level 3 (d) (e)1.0 — — — — — 
Transfers out of Level 3 (e)(3.0)— — — — — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
240.0 91.3 10.8 (2.1)65.3 56.6 
Balance as of September 30, 2025$327.1 $91.3 $10.9 $(44.3)$65.3 $56.6 

Nine Months Ended September 30, 2024AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of December 31, 2023$139.4 $22.4 $2.8 $(50.6)$18.6 $11.1 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
90.6 24.1 7.3 (0.9)26.2 23.6 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
2.3 — — — — — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
1.5 — — — — — 
Settlements(164.7)(46.5)(10.0)6.0 (44.8)(36.0)
Transfers into Level 3 (d) (e)6.8 — — — — — 
Transfers out of Level 3 (e)2.2 — — — — 0.5 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
115.0 47.2 9.2 (6.1)28.4 24.5 
Balance as of September 30, 2024$193.1 $47.2 $9.3 $(51.6)$28.4 $23.7 

(a)Included in revenues on the statements of income.
(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)Included in cash flow hedges on the statements of comprehensive income.
(d)Represents existing assets or liabilities that were previously categorized as Level 2.
(e)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(f)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable.
171

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:

Significant Unobservable Inputs
September 30, 2025
SignificantInput/Range
Type ofFair ValueValuationUnobservableWeighted
CompanyInputAssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
AEPEnergy Contracts$225.7 $141.2 Discounted Cash FlowForward Market Price$2.24 $144.31 $49.61 
AEPFTRs251.0 8.4 Discounted Cash FlowForward Market Price(33.94)45.81 (0.06)
APCoFTRs91.4 0.1 Discounted Cash FlowForward Market Price(1.01)12.36 2.44 
I&MFTRs11.3 0.4 Discounted Cash FlowForward Market Price(0.16)14.70 1.28 
OPCoEnergy Contracts— 44.3 Discounted Cash FlowForward Market Price13.67 78.67 43.36 
PSOFTRs68.3 3.0 Discounted Cash FlowForward Market Price(33.94)9.23 (6.03)
SWEPCoFTRs59.4 2.8 Discounted Cash FlowForward Market Price(33.94)9.23 (6.03)

December 31, 2024
SignificantInput/Range
Type ofFair ValueValuationUnobservableWeighted
CompanyInputAssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
AEPEnergy Contracts$221.2 $144.6 Discounted Cash FlowForward Market Price$2.75 $149.30 $49.34 
AEPFTRs92.3 3.3 Discounted Cash FlowForward Market Price(29.48)19.70 0.24 
APCoFTRs35.2 — Discounted Cash FlowForward Market Price(0.25)9.32 1.56 
I&MFTRs6.9 0.5 Discounted Cash FlowForward Market Price(4.07)9.32 1.34 
OPCoEnergy Contracts— 47.5 Discounted Cash FlowForward Market Price14.53 72.40 42.44 
PSOFTRs20.8 0.8 Discounted Cash FlowForward Market Price(29.48)10.54 (3.88)
SWEPCoFTRs18.1 0.6 Discounted Cash FlowForward Market Price(29.48)10.54 (3.88)
(a)Represents market prices in dollars per MWh.
(b)The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term.

The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of September 30, 2025 and December 31, 2024:
Significant Unobservable InputPositionChange in InputImpact on Fair Value Measurement
Forward Market PriceBuyIncrease (Decrease)Higher (Lower)
Forward Market PriceSellIncrease (Decrease)Lower (Higher)
172

11.  INCOME TAXES

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

Effective Tax Rates (ETR)

The Registrants’ interim ETR reflect the estimated annual ETR for 2025 and 2024, adjusted for tax expense associated with certain discrete items. AEP recognized tax benefits in 2024 and 2025 driven by a remeasurement of Excess ADIT which significantly impacted several Registrants’ interim ETR. In the first quarter of 2024, AEP recognized a $224 million tax benefit related to the reduction of a regulatory liability associated with the NOLC PLRs received from the IRS, primarily impacting I&M, PSO and SWEPCo. In the second quarter of 2025, AEP recognized a $383 million tax benefit related to the remeasurement of Excess ADIT associated with the FERC order related to the treatment of NOLCs in transmission formula rates, primarily impacting AEPTCo. The tax benefits in each year are the primary drivers of variances in the Registrants’ interim ETR for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2025.

The ETR for each of the Registrants are included in the following tables:

Three Months Ended September 30, 2025
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State and Local Income Taxes, Net1.2 %0.6 %2.5 %(1.2)%2.8 %1.0 %3.0 %(3.9)%
Tax Reform Excess ADIT Reversal
(2.5)%(2.3)%0.2 %(3.5)%(5.5)%(2.7)%(4.8)%(3.2)%
Production and Investment Tax Credits(7.9)%(0.1)%— %0.1 %(26.6)%— %(50.6)%(27.5)%
Reversal of Origination Flow-Through1.3 %0.1 %0.3 %6.7 %2.2 %0.6 %0.2 %0.7 %
AFUDC Equity(1.6)%(1.8)%(2.5)%(0.5)%(1.1)%(1.8)%(1.2)%(1.1)%
Flow-Through of CAMT0.6 %— %— %6.2 %— %— %— %— %
Other
0.1 %0.1 %— %(0.7)%(0.8)%(0.3)%0.1 %— %
Effective Income Tax Rate12.2 %17.6 %21.5 %28.1 %(8.0)%17.8 %(32.3)%(14.0)%

Three Months Ended September 30, 2024
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State and Local Income Taxes, Net0.6 %0.3 %2.5 %1.4 %0.7 %1.1 %— %(2.6)%
Tax Reform Excess ADIT Reversal(2.8)%(1.0)%0.2 %(2.3)%(7.9)%(7.3)%(5.0)%(3.2)%
Production and Investment Tax Credits(9.9)%— %— %(0.1)%(45.6)%— %(61.9)%(23.4)%
Reversal of Origination Flow-Through0.1 %0.1 %0.3 %(1.1)%0.3 %0.7 %0.3 %0.6 %
AFUDC Equity(1.5)%(2.3)%(1.9)%(1.5)%(1.2)%(1.2)%(1.3)%(0.5)%
Discrete Tax Adjustments(3.7)%— %— %— %— %— %— %— %
Other
— %0.2 %(0.2)%(0.4)%— %0.6 %1.5 %— %
Effective Income Tax Rate3.8 %18.3 %21.9 %17.0 %(32.7)%14.9 %(45.4)%(8.1)%


173

Nine Months Ended September 30, 2025
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State and Local Income Taxes, Net1.0 %0.6 %2.5 %0.4 %2.4 %1.2 %3.0 %(3.3)%
Tax Reform Excess ADIT Reversal
(1.8)%(2.6)%0.4 %(2.7)%(2.5)%(3.0)%(4.1)%(2.0)%
Remeasurement of Excess ADIT(12.4)%— %(25.5)%(5.9)%(12.8)%— %(8.8)%(17.2)%
Production and Investment Tax Credits(7.1)%(0.1)%— %— %(20.9)%— %(50.9)%(31.0)%
Reversal of Origination Flow-Through0.6 %0.1 %0.2 %0.5 %2.0 %0.6 %0.2 %0.7 %
AFUDC Equity(1.2)%(1.4)%(1.5)%(0.7)%(0.9)%(1.7)%(1.1)%(1.3)%
Flow-Through of CAMT0.2 %— %— %1.7 %— %— %— %— %
Other
0.1 %— %0.1 %— %(0.3)%— %— %0.2 %
Effective Income Tax Rate0.4 %17.6 %(2.8)%14.3 %(12.0)%18.1 %(40.7)%(32.9)%

Nine Months Ended September 30, 2024
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State and Local Income Taxes, Net1.2 %0.4 %2.5 %2.1 %1.5 %0.9 %— %(2.6)%
Tax Reform Excess ADIT Reversal(3.1)%(1.1)%0.2 %(7.1)%(5.7)%(8.7)%(4.3)%(4.2)%
Remeasurement of Excess ADIT(11.9)%1.5 %— %— %(27.5)%— %(40.5)%(181.8)%
Production and Investment Tax Credits(8.3)%(0.1)%— %(0.1)%(23.4)%— %(61.7)%(79.1)%
Reversal of Origination Flow-Through0.2 %0.1 %0.3 %(0.8)%0.3 %0.8 %0.3 %2.1 %
AFUDC Equity(1.6)%(1.7)%(2.0)%(1.1)%(1.1)%(1.3)%(1.3)%(2.3)%
Discrete Tax Adjustments(2.1)%— %— %— %— %— %1.2 %1.1 %
Other
0.2 %— %(0.1)%(0.1)%— %0.4 %— %(0.5)%
Effective Income Tax Rate(4.4)%20.1 %21.9 %13.9 %(34.9)%13.1 %(85.3)%(246.3)%

Federal and State Income Tax Audit Status

AEP is not currently under IRS audit and the statute of limitations (SOL) for the IRS to examine AEP and subsidiaries originally filed federal return has expired for tax years prior to 2022. In July 2025, AEP received notification that its 2023 federal income tax return was selected for IRS examination. However, this examination has yet to begin.

AEP and subsidiaries file income tax returns in various state and local jurisdictions. AEP and subsidiaries are not currently under any state and local income tax examinations. Generally, the SOL have expired for tax years prior to 2022. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

Federal Legislation

On July 4, 2025, President Trump signed H.R. 1 into law, commonly known as the One Big Beautiful Bill Act (OBBBA). This budget reconciliation legislation modifies and accelerates the phase out of technology neutral PTCs and ITCs available for wind and solar projects, adds new restrictions to guard against certain foreign ownership or influence with respect to otherwise credit-eligible projects and makes 100% bonus depreciation permanent for certain non-regulated entities. With the exception of bonus depreciation, this legislation is prospective and has no material impact on the current period financial statements.

174

On August 15, 2025, the Department of Treasury and the IRS issued new and revised wind and solar tax credit guidance, Notice 2025-42, which modified the definition of “begin construction” for tax purposes by eliminating the previously available 5% cost safe harbor standard for projects that begin construction after September 1, 2025. This guidance is not expected to have a material impact on the Registrants.

On September 30, 2025, the Department of Treasury and the IRS issued interim guidance regarding the application of CAMT. The Registrants are subject to CAMT and will continue to evaluate the impact of that interim guidance.

Additional significant guidance from the Department of Treasury and the IRS is expected on the tax provisions in recently enacted legislation. AEP will continue to monitor any issued guidance and evaluate the impact on AEP’s future net income, cash flows and financial condition.
175

12.  VOLUNTARY SEVERANCE PROGRAM

In April 2024, management announced a voluntary severance program designed to achieve a reduction in the size of AEP’s workforce. Approximately 7,400 of AEP’s 16,800 employees were eligible to participate in the program. Approximately 1,000 employees chose to take the voluntary severance package and substantially all terminated employment in July 2024. The severance program provides two weeks of base pay for every year of service with a minimum of four weeks and a maximum of 52 weeks of base pay. Certain positions impacted by the voluntary severance program have been and will continue to be refilled to maintain safe, effective and efficient operations. Net savings from the program will help offset increasing operating expenses and high interest costs in order to keep electricity costs affordable for customers.

AEP recorded a charge to expense in the second quarter of 2024 related to this voluntary severance program.

AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Severance Expense Incurred$122.0 $19.8 $10.7 $26.5 $14.8 $14.8 $10.1 $16.9 

These expenses were primarily included in Other Operation and Maintenance on the statements of income and Other Current Liabilities on the balance sheets. Settlement accounting was triggered for the qualified pension plan in November 2024 under the accounting guidance for “Compensation - Retirement Benefits” and a settlement charge of $90 million was recorded. As of September 30, 2025, all incurred expenses have been settled. AEP will seek recovery for the portion of the expense related to regulated operations. See Note 7 - Benefit Plans for additional information associated with the plan.
176

13.  FINANCING ACTIVITIES

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

Common Stock (Applies to AEP)

At-the-Market (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 nine months ended September 30, 2025. Approximately $1.3 billion of equity is available for issuance under the ATM program upon the filing of a prospectus supplement.

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 September 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.

Long-term Debt Outstanding (Applies to AEP)

The following table details long-term debt outstanding, net of issuance costs and premiums or discounts:
Type of DebtSeptember 30, 2025December 31, 2024
 (in millions)
Senior Unsecured Notes$37,865.2 $36,410.9 
Pollution Control Bonds1,685.7 1,771.3 
Notes Payable614.8 609.9 
Securitization Bonds983.3 578.0 
Spent Nuclear Fuel Obligation (a)326.7 316.3 
Junior Subordinated Notes3,707.9 2,579.1 
Other Long-term Debt954.0 377.3 
Total Long-term Debt Outstanding46,137.6 42,642.8 
Long-term Debt Due Within One Year1,898.6 3,335.0 
Long-term Debt$44,239.0 $39,307.8 

(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $381 million and $367 million as of September 30, 2025 and December 31, 2024, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.


177

Long-term Debt Activity

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2025 are shown in the following tables:
PrincipalInterest
CompanyType of DebtAmount (a)RateDue Date
Issuances: (in millions)(%)
AEPJunior Subordinated Notes $1,100.0 5.802056
AEPJunior Subordinated Notes 900.0 6.052056
AEP TexasOther Long-term Debt400.0 Variable2026
AEP TexasSenior Unsecured Notes150.0 5.702034
AEP TexasSenior Unsecured Notes750.0 5.852055
AEPTCoOther Long-term Debt141.0 Variable2028
AEPTCoSenior Unsecured Notes425.0 5.382035
APCoOther Long-term Debt425.0 Variable2026
APCoPollution Control Bonds104.4 3.702028
APCoPollution Control Bonds65.3 3.302028
I&MNotes Payable100.0 4.892029
I&MPollution Control Bonds150.0 3.702029
PSOSenior Unsecured Notes800.05.452036
Non-Registrant:
KPCoOther Long-term Debt150.0 Variable2026
KPCoSecuritization Bonds477.7 5.302045
Transource EnergyOther Long-term Debt36.6 Variable2025
WPCoOther Long-term Debt125.0 Variable2026
Total Issuances$6,300.0 

(a)Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

178

PrincipalInterest
CompanyType of DebtAmount PaidRateDue Date
Retirements and Principal Payments:
(in millions)(%)
AEPJunior Subordinated Notes$850.0 5.702025
AEP TexasOther Long-term Debt400.0 Variable2026
AEP TexasSecuritization Bonds10.3 2.062025
AEP TexasSecuritization Bonds14.2 2.292029
AEP TexasSenior Unsecured Notes50.0 3.752025
AEPTCoSenior Unsecured Notes50.0 3.662025
AEPTCoSenior Unsecured Notes40.0 3.762025
APCoOther Long-term Debt0.1 13.722026
APCoPollution Control Bonds104.4 3.752025
APCoPollution Control Bonds65.4 1.002025
APCoSecuritization Bonds28.4 3.772028
APCoSenior Unsecured Notes300.0 3.402025
I&MNotes Payable3.9 0.932025
I&MNotes Payable1.1 Variable2025
I&MNotes Payable8.4 3.442026
I&MNotes Payable13.2 5.932027
I&MNotes Payable24.6 6.412028
I&MNotes Payable15.4 6.012028
I&MNotes Payable13.1 4.892029
I&MOther Long-term Debt0.2 6.002025
I&MPollution Control Bonds100.0 3.052025
I&MPollution Control Bonds50.0 2.752025
I&MPollution Control Bonds40.0 0.752025
PSOOther Long-term Debt0.4 3.002027
PSOSenior Unsecured Notes125.0 3.172025
SWEPCoSecuritization Bonds11.1 4.882039
Non-Registrant:
AEGCoPollution Control Bonds45.0 1.352025
KPCoOther Long-term Debt150.0 Variable2025
KPCoOther Long-term Debt150.0 Variable2026
Transource EnergySenior Unsecured Notes2.6 2.752050
WPCoNotes Payable15.0 6.892034
WPCoSenior Unsecured Notes122.0 3.702025
Total Retirements and Principal Payments
$2,803.8 

Long-term Debt Subsequent Events

In October 2025, I&M issued $103 million of variable rate Notes Payable due in 2030.

In October 2025, I&M retired $8 million of Notes Payable related to DCC Fuel.

In October 2025, Transource Energy issued $4 million of variable rate Other Long-term Debt due in 2028.

Debt Covenants (Applies to AEP and AEPTCo)

Covenants in AEPTCo’s note purchase agreements and indenture limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. AEPTCo’s contractually-defined priority debt was 0.7% of consolidated tangible net assets as of September 30, 2025. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreements.


179

Dividend Restrictions

Utility Subsidiaries’ Restrictions

Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends.

All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act requirement that prohibits the payment of dividends out of capital accounts in certain circumstances; payment of dividends is generally allowed out of retained earnings. The Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to APCo and I&M.

Certain AEP subsidiaries have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.

The Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings.

Parent Restrictions (Applies to AEP)

The holders of AEP’s common stock are entitled to receive the dividends declared by the AEP Board provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.

Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.

Corporate Borrowing Program (Applies to all Registrant Subsidiaries)

AEP subsidiaries use a corporate borrowing program to meet their short-term borrowing needs. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP. The AEP Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2025 and December 31, 2024 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits for the nine months ended September 30, 2025 are described in the following table:
MaximumAverageNet Loans to
BorrowingsMaximumBorrowingsAverage(Borrowings from)Authorized
from theLoans to thefrom theLoans to thethe Utility MoneyShort-term
UtilityUtilityUtilityUtilityPool as ofBorrowing
CompanyMoney PoolMoney PoolMoney PoolMoney PoolSeptember 30, 2025Limit
 (in millions)
AEP Texas$468.4 $485.7 $172.6 $82.5 $418.1 $600.0 
AEPTCo403.6 312.2 174.8 44.2 (89.3)820.0 (a)
APCo263.5 242.1 127.8 26.1 49.6 750.0 
I&M145.2 157.2 71.4 46.2 157.2 500.0 
OPCo270.9 165.9 126.0 81.7 (13.0)600.0 
PSO505.1 391.5 221.2 166.1 (39.7)750.0 
SWEPCo471.9 269.7 285.9 88.7 269.7 750.0 

(a)    Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.


180

The activity in the above table does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2025 and December 31, 2024 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the nine months ended September 30, 2025 is described in the following table:
Maximum Loans Average Loans Loans to the Nonutility
to the Nonutility to the Nonutility Money Pool as of
CompanyMoney PoolMoney PoolSeptember 30, 2025
(in millions)
AEP Texas$7.2 $7.1 $7.2 
SWEPCo2.4 2.1 — 

AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of September 30, 2025 and December 31, 2024 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct financing activities with AEP and corresponding authorized borrowing limit for the nine months ended September 30, 2025 are described in the following table:
BorrowingsAuthorized
MaximumMaximumAverageAveragefrom AEPLoans toShort-term
BorrowingsLoansBorrowingsLoansas of AEP as ofBorrowing
Companyfrom AEP to AEP from AEP to AEP September 30, 2025September 30, 2025Limit (a)
(in millions)
AEPTCo Parent$106.6 $132.6 $17.7 $45.3 $— $49.7 $— 
SWTCo2.0 — 1.9 — 2.0 — 50.0 
Midwest Transmission Holdings— 34.1 — 6.1 — 0.3 — 

(a)    Amount represents the authorized short-term borrowing limit from FERC or state regulatory agencies not otherwise included in the utility money pool above.

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:
 Nine Months Ended September 30,
20252024
Maximum Interest Rate4.83 %5.79 %
Minimum Interest Rate4.00 %5.14 %

The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized in the following table:
Average Interest Rate for FundsAverage Interest Rate for Funds
Borrowed from the Utility Money PoolLoaned to the Utility Money Pool
for Nine Months Ended September 30,for Nine Months Ended September 30,
Company2025202420252024
AEP Texas4.67 %5.69 %4.37 %5.48 %
AEPTCo4.65 %5.68 %4.62 %5.58 %
APCo4.67 %5.72 %4.58 %5.51 %
I&M4.69 %5.64 %4.50 %5.44 %
OPCo4.61 %5.70 %4.70 %5.49 %
PSO4.64 %5.59 %4.68 %— %
SWEPCo4.69 %5.58 %4.55 %— %

181

Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:
Nine Months Ended September 30, 2025Nine Months Ended September 30, 2024
  Maximum Minimum AverageMaximum Minimum Average
  Interest Rate Interest Rate Interest RateInterest Rate Interest Rate Interest Rate
  for Funds for Funds for Fundsfor Funds for Funds for Funds
 Loaned to Loaned to Loaned toLoaned to Loaned to Loaned to
 the Nonutility the Nonutility the Nonutilitythe Nonutility the Nonutility the Nonutility
Company Money Pool Money Pool Money PoolMoney Pool Money Pool Money Pool
AEP Texas 4.76 %4.27 %4.66 %5.79 %5.25 %5.64 %
SWEPCo 4.76 %4.62 %4.69 %5.79 %5.25 %5.64 %

AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:

 MaximumMinimumMaximumMinimumAverageAverage
 Interest RateInterest RateInterest RateInterest RateInterest RateInterest Rate
Nine Months for Fundsfor Fundsfor Fundsfor Fundsfor Fundsfor Funds
Ended BorrowedBorrowedLoanedLoanedBorrowedLoaned
September 30, from AEP from AEPto AEP to AEP from AEP to AEP
2025 4.76 %4.27 %4.76 %4.27 %4.64 %4.64 %
2024 5.79 %5.25 %5.79 %5.25 %5.66 %5.63 %

Short-term Debt (Applies to AEP and SWEPCo)

Outstanding short-term debt was as follows:
 September 30, 2025December 31, 2024
OutstandingInterestOutstandingInterest
CompanyType of DebtAmountRate (a)AmountRate (a)
 (dollars in millions)
AEPSecuritized Debt for Receivables (b)$900.0 4.56 %$900.0 4.73 %
AEPCommercial Paper250.0 4.30 %1,618.3 4.70 %
SWEPCoNotes Payable7.7 6.50 %5.5 6.69 %
Total Short-term Debt$1,157.7  $2,523.8  

(a)Weighted-average rate as of September 30, 2025 and December 31, 2024, respectively.
(b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.


182

Securitized Accounts Receivables – AEP Credit (Applies to AEP)

AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.

AEP Credit’s receivables securitization agreement provides a commitment of $900 million from bank conduits to purchase receivables and expires in September 2027. As of September 30, 2025, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

Accounts receivable information for AEP Credit was as follows:
Three Months Ended September 30,Nine Months Ended September 30,
2025202420252024
(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable
4.52 %5.50 %4.56 %5.54 %
Net Uncollectible Accounts Receivable Written-Off$10.8 $8.4 $24.7 $22.3 

September 30, 2025December 31, 2024
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts
$1,292.8 $1,117.0 
Short-term – Securitized Debt of Receivables900.0 900.0 
Delinquent Securitized Accounts Receivable 79.4 56.2 
Bad Debt Reserves Related to Securitization43.4 44.5 
Unbilled Receivables Related to Securitization319.4 335.5 

AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.

Securitized Accounts Receivables – AEP Credit (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo)

Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were:
CompanySeptember 30, 2025December 31, 2024
 (in millions)
APCo$183.0 $192.7 
I&M185.0 160.5 
OPCo490.9 470.7 
PSO202.5 111.4 
SWEPCo200.3 153.5 

183

The fees paid to AEP Credit for customer accounts receivable sold were:
 Three Months Ended September 30,Nine Months Ended September 30,
Company2025202420252024
 (in millions)
APCo$3.7 $4.0 $10.9 $12.1 
I&M4.2 4.1 11.2 12.0 
OPCo7.4 7.5 22.3 22.3 
PSO4.0 4.1 9.7 10.9 
SWEPCo4.1 4.4 11.9 13.5 
The proceeds on the sale of receivables to AEP Credit were:
 Three Months Ended September 30,Nine Months Ended September 30,
Company2025202420252024
(in millions)
APCo$495.4 $504.6 $1,530.0 $1,487.9 
I&M682.6 576.7 1,812.7 1,608.5 
OPCo927.8 860.0 2,523.3 2,477.2 
PSO659.6 611.5 1,466.3 1,398.1 
SWEPCo549.9 531.4 1,434.0 1,428.7 

184

14. VARIABLE INTEREST ENTITIES

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

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE.  A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.

AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. AEP has not provided material financial or other support that was not previously contractually required to any of its consolidated VIEs. AEP’s interests in non-consolidated VIEs are accounted for under the equity method of accounting.

Consolidated Variable Interest Entities

Cost Recovery Funding (Applies to AEP)

In June 2025, Cost Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to plant retirement costs, deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, deferred purchased power expenses, under-recovered purchased power rider costs and issuance-related expenses, including KPSC advisor expenses. Management concluded that KPCo is the primary beneficiary of Cost Recovery Funding because KPCo has the power to direct the most significant activities of the VIE and KPCo’s equity interest could potentially be significant. Therefore, KPCo is required to consolidate Cost Recovery Funding. As of September 30, 2025, $16 million of the securitized bonds was included in Long-term Debt Due Within One Year and $452 million was included in Long-term Debt on the balance sheet. Cost Recovery Funding’s securitized assets were $465 million as of September 30, 2025, which was presented separately on the face of the balance sheet.

The securitized assets represent the right to impose and collect KPCo recovery charges from KPCo’s customers. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to KPCo or any other AEP entity. KPCo acts as the servicer for Cost Recovery Funding’s securitized assets and remits all related amounts collected from customers to Cost Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Cost Recovery Funding’s assets and liabilities on the balance sheet.

The 2024 Annual Report includes a detailed discussion of AEP’s and Registrant Subsidiaries’ other consolidated VIEs.
185

The balances below represent the assets and liabilities of AEP’s and Registrant Subsidiaries’ consolidated VIEs. These balances include intercompany transactions that are eliminated upon consolidation.

September 30, 2025
Consolidated VIEs
SWEPCo
Sabine		I&M
DCC Fuel		AEP Texas Restoration FundingAPCo Appalachian Consumer Rate Relief FundingSWEPCo Storm Recovery FundingKPCo Cost Recovery FundingAEP CreditProtected
Cell
of EIS		Transource Energy
(in millions)
ASSETS
Current Assets$2.0 $86.7 $12.5 $9.7 $9.1 $14.2 $1,640.7 $227.2 $63.7 
Net Property, Plant and Equipment— 152.2 — — — — — — 633.0 
Other Noncurrent Assets92.9 76.4 104.6 (a)86.2 (b)315.3 465.0 (c)10.9 0.5 6.6 
Total Assets$94.9 $315.3 $117.1 $95.9 $324.4 $479.2 $1,651.6 $227.7 $703.3 
LIABILITIES AND EQUITY
Current Liabilities$18.1 $86.5 $30.3 $30.2 $18.4 $24.1 $1,529.6 $64.7 $31.2 
Noncurrent Liabilities76.8 228.8 85.4 63.8 304.3 452.7 1.0 94.2 339.8 
Equity— — 1.4 1.9 1.7 2.4 121.0 68.8 332.3 
Total Liabilities and Equity$94.9 $315.3 $117.1 $95.9 $324.4 $479.2 $1,651.6 $227.7 $703.3 

(a)Includes an intercompany item eliminated in consolidation of $4 million.
(b)Includes an intercompany item eliminated in consolidation of $1 million.
(c)Includes an intercompany item eliminated in consolidation of $16 million.

December 31, 2024
Consolidated VIEs
SWEPCo
Sabine		I&M
DCC Fuel		AEP Texas Restoration FundingAPCo
Appalachian
Consumer
Rate Relief Funding		SWEPCo Storm Recovery FundingAEP CreditProtected
Cell
of EIS		Transource Energy
(in millions)
ASSETS
Current Assets$6.0 $79.3 $21.3 $14.2 $3.4 $1,118.3 $218.5 $40.2 
Net Property, Plant and Equipment— 132.3 — — — — — 598.3 
Other Noncurrent Assets110.863.6121.9 (a)109.6(b)331.410.5 — 3.5 
Total Assets$116.8 $275.2 $143.2 $123.8 $334.8 $1,128.8 $218.5 $642.0 
LIABILITIES AND EQUITY
Current Liabilities$20.1 $79.2 $30.7 $30.5 $24.4 $1,068.8 $54.7 $57.2 
Noncurrent Liabilities96.3 196.0 111.2 91.4308.71.096.0 274.3 
Equity0.4— 1.31.91.759.0 67.8 310.5 
Total Liabilities and Equity$116.8 $275.2 $143.2 $123.8 $334.8 $1,128.8 $218.5 $642.0 

(a)Includes an intercompany item eliminated in consolidation of $5 million.
(b)Includes an intercompany item eliminated in consolidation of $1 million.



186

Non-Consolidated Significant Variable Interests

The 2024 Annual Report includes a detailed discussion of AEP’s and Registrant Subsidiaries’ significant variable interests in non-consolidated VIEs.

Equity Method Investment in Unconsolidated Entities

Gigawatt AI (Applies to AEP)

In August 2025, AEP and Gigawatt AI, Inc. (GWAI), a recently formed privately held company, entered into a new commercial arrangement. GWAI is focused on developing AI-centric operating systems and applications that optimize utility operations and infrastructure. AEP invested $100 million for a 10% ownership interest in the common stock and received a warrant for the option to acquire an additional 5% of GWAI’s common stock for $50 million. Contingent upon GWAI’s achievement of defined performance-based milestones, AEP will invest up to an additional $100 million for up to an additional 10% of GWAI’s common stock. In connection with AEP’s equity interest, AEP was granted the right to designate one of the three members of GWAI’s board of directors, which position is currently held by an officer of AEP. All other equity interests and representation on the board of directors are held by the founders of GWAI. Accordingly, the investment represents a related-party transaction. AEP also acquired a perpetual software license for software developed by GWAI.

The $100 million equity interest is accounted for as an equity method investment due to AEP’s ability to exercise significant influence over certain GWAI policies. As of September 30, 2025, AEP’s carrying value of the investment in GWAI was $100 million, which was initially recognized at cost in Deferred Charges and Other Noncurrent Assets on the balance sheet. AEP’s proportionate share of GWAI’s earnings or losses were immaterial for the three and nine months ended September 30, 2025.

The common stock warrant meets the definition of a derivative instrument and is therefore required to be carried at fair value on a recurring basis. The fair value of the common stock warrant and AEP's acquired perpetual software license were immaterial as of September 30, 2025. GWAI’s successful development of new, substantive software functionality that can feasibly be deployed and implemented by the Registrants may give rise to an impairment trigger for other internal-use software assets in future reporting periods.

The 2024 Annual Report includes a detailed discussion of AEP’s and Registrant Subsidiaries’ other equity method investments.

187

15. PROPERTY, PLANT AND EQUIPMENT

The disclosures in this note apply to AEP, PSO and SWEPCo.

Asset Retirement Obligations

The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal mining facilities. AEP records ARO for the decommissioning of the Cook Plant. The table below summarizes significant changes to the Registrants ARO recorded in 2025 and should be read in conjunction with the Property, Plant and Equipment note within the 2024 Annual Report.

The following is a reconciliation of the aggregate carrying amounts of ARO for AEP, PSO and SWEPCo:
Company
ARO as of December 31, 2024
Accretion
Expense		Liabilities
Incurred		Liabilities
Settled		Revisions in
Cash Flow
Estimates (a)
ARO as of September 30, 2025
(in millions)
AEP (b)(c)(d)(e)(f)(g)$3,611.7 $127.4 $21.2 $(68.3)$36.2 $3,728.2 
PSO (b)(e)(f)(g)121.8 5.7 19.3 (1.9)(2.8)142.1 
SWEPCo (b)(d)(e)(f) 278.7 12.7 — (42.4)33.0 282.0 

(a)Unless discussed above, primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs.
(b)Includes ARO related to ash disposal facilities.
(c)Includes ARO related to nuclear decommissioning costs for the Cook Plant.
(d)Includes ARO related to Sabine and DHLC.
(e)Includes ARO related to asbestos removal.
(f)Includes ARO related to renewables.
(g)Includes ARO related to incurred ARO liabilities due to the acquisitions of Pixley Solar Energy Facility, Flat Ridge IV Wind Energy Facility and Flat Ridge V Wind Energy Facility. See the “Acquisitions” section of Note 6 for additional information.


188

16. REVENUE FROM CONTRACTS WITH CUSTOMERS

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

Disaggregated Revenues from Contracts with Customers

The tables below represent AEP’s reportable segment and Registrant Subsidiary revenues from contracts with customers, net of respective provisions for refund, by type of revenue:
Three Months Ended September 30, 2025
VIUT&DAEPTHCoG&MCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$1,435.8 $797.8 $— $— $— $— $2,233.6 
Commercial Revenues861.7 422.7 — — — — 1,284.4 
Industrial Revenues (a)709.8 133.7 — — — (0.1)843.4 
Other Retail Revenues67.0 15.4 — — — — 82.4 
Total Retail Revenues3,074.3 1,369.6 — — — (0.1)4,443.8 
Wholesale and Competitive Retail Revenues:
Generation Revenues 259.6 — — 50.5 — — 310.1 
Transmission Revenues (b)141.3 210.0 531.3 — — (479.5)403.1 
Renewable Generation Revenues— — — 0.1 — — 0.1 
Retail, Trading and Marketing Revenues (c)— — — 648.0 — (18.9)629.1 
Total Wholesale and Competitive Retail Revenues
400.9 210.0 531.3 698.6 — (498.4)1,342.4 
Other Revenues from Contracts with Customers (d)96.1 84.4 12.0 3.0 34.1 (53.7)175.9 
Total Revenues from Contracts with Customers
3,571.3 1,664.0 543.3 701.6 34.1 (552.2)5,962.1 
Other Revenues:
Alternative Revenue Programs (e)8.6 17.6 29.8 — — (32.0)24.0 
Other Revenues (a) (f)5.8 7.7 0.1 11.1 1.8 (2.2)24.3 
Total Other Revenues14.4 25.3 29.9 11.1 1.8 (34.2)48.3 
Total Revenues$3,585.7 $1,689.3 $573.2 $712.7 $35.9 $(586.4)$6,010.4 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $423 million. The affiliated revenues for Vertically Integrated Utilities were $56 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $18 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $31 million. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $25 million. The remaining affiliated amounts were immaterial.
(f)Generation & Marketing includes economic hedge activity.
189

Three Months Ended September 30, 2024
VIUT&DAEPTHCoG&MCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$1,362.9 $773.7 $— $— $— $— $2,136.6 
Commercial Revenues776.1 396.5 — — — — 1,172.6 
Industrial Revenues (a)692.6 123.7 — — — (0.3)816.0 
Other Retail Revenues63.8 13.9 — — — — 77.7 
Total Retail Revenues2,895.4 1,307.8 — — — (0.3)4,202.9 
Wholesale and Competitive Retail Revenues:
Generation Revenues 202.5 — — 25.4 — 0.1 228.0 
Transmission Revenues (b)129.6 195.1 505.5 — — (439.4)390.8 
Renewable Generation Revenues (a)— — — 8.7 — (1.5)7.2 
Retail, Trading and Marketing Revenues (c)— — — 529.3 (0.2)(13.8)515.3 
Total Wholesale and Competitive Retail Revenues
332.1 195.1 505.5 563.4 (0.2)(454.6)1,141.3 
Other Revenues from Contracts with Customers (d)76.2 58.9 5.8 0.8 37.6 (53.4)125.9 
Total Revenues from Contracts with Customers
3,303.7 1,561.8 511.3 564.2 37.4 (508.3)5,470.1 
Other Revenues:
Alternative Revenue Programs (a) (e)0.3 10.3 1.2 — — 1.0 12.8 
Other Revenues (a) (f)(1.0)3.3 — (65.1)0.7 (0.7)(62.8)
Total Other Revenues(0.7)13.6 1.2 (65.1)0.7 0.3 (50.0)
Total Revenues$3,303.0 $1,575.4 $512.5 $499.1 $38.1 $(508.0)$5,420.1 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $402 million. The affiliated revenues for Vertically Integrated Utilities were $51 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $14 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $34 million. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
(f)Generation & Marketing includes economic hedge activity.

190

Three Months Ended September 30, 2025
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$243.6 $— $438.2 $249.1 $554.2 $334.9 $296.8 
Commercial Revenues123.9 — 194.0 216.8 298.8 184.4 189.0 
Industrial Revenues (a)41.6 — 197.7 150.1 92.1 112.1 112.3 
Other Retail Revenues11.3 — 26.8 1.2 4.0 33.7 3.5 
Total Retail Revenues420.4 — 856.7 617.2 949.1 665.1 601.6 
Wholesale Revenues:
Generation Revenues (b)— — 106.1 141.1 — 6.1 43.2 
Transmission Revenues (c)184.3 515.9 44.4 11.1 25.7 8.1 60.9 
Total Wholesale Revenues184.3 515.9 150.5 152.2 25.7 14.2 104.1 
Other Revenues from Contracts with Customers (d)10.4 12.0 42.2 35.9 74.0 13.7 15.8 
Total Revenues from Contracts with Customers
615.1 527.9 1,049.4 805.3 1,048.8 693.0 721.5 
Other Revenues:
Alternative Revenue Programs (e)3.8 30.1 6.5 0.9 13.6 0.3 2.4 
Other Revenues (a)0.2 — 0.1 6.0 7.8 0.1 — 
Total Other Revenues4.0 30.1 6.6 6.9 21.4 0.4 2.4 
Total Revenues$619.1 $558.0 $1,056.0 $812.2 $1,070.2 $693.4 $723.9 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $41 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $419 million, $19 million and $28 million, respectively. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $19 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo were $25 million. The remaining affiliated amounts were immaterial.

191

Three Months Ended September 30, 2024
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$230.2 $— $442.6 $249.4 $543.4 $301.1 $260.1 
Commercial Revenues120.3 — 196.4 169.9 276.2 165.1 172.5 
Industrial Revenues (a)33.7 — 201.2 155.4 89.9 98.5 102.5 
Other Retail Revenues9.7 — 28.1 1.2 4.2 30.8 2.3 
Total Retail Revenues393.9 — 868.3 575.9 913.7 595.5 537.4 
Wholesale Revenues:
Generation Revenues (b)— — 78.7 113.5 — 2.1 42.7 
Transmission Revenues (c)170.6 491.9 45.6 10.4 24.5 12.0 50.0 
Total Wholesale Revenues170.6 491.9 124.3 123.9 24.5 14.1 92.7 
Other Revenues from Contracts with Customers (d)8.2 6.0 36.2 35.3 50.8 6.0 8.8 
Total Revenues from Contracts with Customers
572.7 497.9 1,028.8 735.1 989.0 615.6 638.9 
Other Revenues:
Alternative Revenue Programs (a) (e)(1.5)(0.7)— (0.4)11.9 (0.2)(0.1)
Other Revenues (a)— — 0.1 (1.2)3.3 — — 
Total Other Revenues(1.5)(0.7)0.1 (1.6)15.2 (0.2)(0.1)
Total Revenues$571.2 $497.2 $1,028.9 $733.5 $1,004.2 $615.4 $638.8 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $41 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $399 million, $22 million and $22 million, respectively. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $18 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.



192

Nine Months Ended September 30, 2025
VIUT&DAEPTHCoG&MCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$3,817.8 $2,148.6 $— $— $— $— $5,966.4 
Commercial Revenues2,276.4 1,225.0 — — — — 3,501.4 
Industrial Revenues (a)2,032.2 401.9 — — — (0.6)2,433.5 
Other Retail Revenues181.9 44.9 — — — — 226.8 
Total Retail Revenues8,308.3 3,820.4 — — — (0.6)12,128.1 
Wholesale and Competitive Retail Revenues:
Generation Revenues801.9 — — 139.8 — — 941.7 
Transmission Revenues (b)419.4 604.4 1,751.0 — — (1,551.8)1,223.0 
Renewable Generation Revenues— — — 0.1 — — 0.1 
Retail, Trading and Marketing Revenues (c)— — — 1,808.2 (0.2)(50.4)1,757.6 
Total Wholesale and Competitive Retail Revenues1,221.3 604.4 1,751.0 1,948.1 (0.2)(1,602.2)3,922.4 
Other Revenues from Contracts with Customers (d)197.1 192.5 29.7 6.4 104.7 (148.3)382.1 
Total Revenues from Contracts with Customers
9,726.7 4,617.3 1,780.7 1,954.5 104.5 (1,751.1)16,432.6 
Other Revenues:
Alternative Revenue Programs (e)26.4 33.5 91.1 — — (94.3)56.7 
Other Revenues (a) (f)(14.4)15.2 0.1 71.3 5.6 (6.4)71.4 
Total Other Revenues12.0 48.7 91.2 71.3 5.6 (100.7)128.1 
Total Revenues$9,738.7 $4,666.0 $1,871.9 $2,025.8 $110.1 $(1,851.8)$16,560.7 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $1.4 billion. The affiliated revenues for Vertically Integrated Utilities were $160 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $50 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $86 million. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $74 million. The remaining affiliated amounts were immaterial.
(f)Generation & Marketing includes economic hedge activity.
193

Nine Months Ended September 30, 2024
VIUT&DAEPTHCoG&MCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$3,524.2 $2,127.7 $— $— $— $— $5,651.9 
Commercial Revenues2,071.0 1,184.6 — — — — 3,255.6 
Industrial Revenues (a)1,992.5 382.8 — — — (0.6)2,374.7 
Other Retail Revenues174.9 41.5 — — — — 216.4 
Total Retail Revenues7,762.6 3,736.6 — — — (0.6)11,498.6 
Wholesale and Competitive Retail Revenues:
Generation Revenues587.4 — — 76.5 — 0.1 664.0 
Transmission Revenues (b)371.5 583.2 1,490.8 — — (1,255.0)1,190.5 
Renewable Generation Revenues (a)— — — 23.2 — (4.3)18.9 
Retail, Trading and Marketing Revenues (c)
— — — 1,586.2 0.6 (83.7)1,503.1 
Total Wholesale and Competitive Retail Revenues
958.9 583.2 1,490.8 1,685.9 0.6 (1,342.9)3,376.5 
Other Revenues from Contracts with Customers (d)183.3 148.8 20.1 3.1 153.2 (170.9)337.6 
Total Revenues from Contracts with Customers
8,904.8 4,468.6 1,510.9 1,689.0 153.8 (1,514.4)15,212.7 
Other Revenues:
Alternative Revenue Programs (a) (e)(12.5)17.7 (11.2)— — (15.3)(21.3)
Other Revenues (a) (f)(22.4)15.2 — (158.9)(5.2)4.9 (166.4)
Total Other Revenues(34.9)32.9 (11.2)(158.9)(5.2)(10.4)(187.7)
Total Revenues$8,869.9 $4,501.5 $1,499.7 $1,530.1 $148.6 $(1,524.8)$15,025.0 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $1.2 billion. The affiliated revenues for Vertically Integrated Utilities were $133 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $84 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $112 million. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
(f)Generation & Marketing includes economic hedge activity.
194

Nine Months Ended September 30, 2025
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$595.7 $— $1,409.8 $671.3 $1,552.9 $700.6 $680.7 
Commercial Revenues357.8 — 582.5 561.5 867.3 421.5 485.1 
Industrial Revenues (a)122.8 — 599.6 440.5 279.1 273.8 305.2 
Other Retail Revenues32.3 — 83.2 3.7 12.6 80.3 8.9 
Total Retail Revenues1,108.6 — 2,675.1 1,677.0 2,711.9 1,476.2 1,479.9 
Wholesale Revenues:
Generation Revenues (b)— — 273.6 474.4 — 11.7 147.5 
Transmission Revenues (c)533.0 1,704.1 132.1 40.1 71.4 37.9 155.2 
Total Wholesale Revenues533.0 1,704.1 405.7 514.5 71.4 49.6 302.7 
Other Revenues from Contracts with
Customers (d)
29.0 29.8 75.1 92.8 163.6 28.8 31.6 
Total Revenues from Contracts with Customers1,670.6 1,733.9 3,155.9 2,284.3 2,946.9 1,554.6 1,814.2 
Other Revenues:
Alternative Revenue Program (e)2.7 93.0 20.2 1.9 30.7 2.2 11.2 
Other Revenues (a)— — 0.4 (14.6)15.1 0.1 — 
Total Other Revenues2.7 93.0 20.6 (12.7)45.8 2.3 11.2 
Total Revenues$1,673.3 $1,826.9 $3,176.5 $2,271.6 $2,992.7 $1,556.9 $1,825.4 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $122 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $1.4 billion, $60 million and $59 million, respectively. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $55 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo were $73 million. The remaining affiliated amounts were immaterial.
195

Nine Months Ended September 30, 2024
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$562.4 $— $1,333.7 $664.7 $1,565.2 $647.1 $563.2 
Commercial Revenues346.2 — 571.8 465.5 838.4 398.2 413.2 
Industrial Revenues (a)103.3 — 603.5 456.4 279.4 269.9 269.8 
Other Retail Revenues28.7 — 84.3 3.8 12.9 78.2 6.6 
Total Retail Revenues1,040.6 — 2,593.3 1,590.4 2,695.9 1,393.4 1,252.8 
Wholesale Revenues:
Generation Revenues (b)— — 235.9 305.6 — 7.0 139.9 
Transmission Revenues (c)511.3 1,450.5 138.3 30.5 71.9 33.0 136.3 
Total Wholesale Revenues511.3 1,450.5 374.2 336.1 71.9 40.0 276.2 
Other Revenues from Contracts with
Customers (d)
27.4 20.3 71.0 92.3 121.5 30.4 26.0 
Total Revenues from Contracts with Customers1,579.3 1,470.8 3,038.5 2,018.8 2,889.3 1,463.8 1,555.0 
Other Revenues:
Alternative Revenue Programs (a) (e)(2.1)(15.6)(6.6)(0.9)19.8 (1.8)(4.2)
Other Revenues (a)— — 0.2 (22.7)15.2 — — 
Total Other Revenues(2.1)(15.6)(6.4)(23.6)35.0 (1.8)(4.2)
Total Revenues$1,577.2 $1,455.2 $3,032.1 $1,995.2 $2,924.3 $1,462.0 $1,550.8 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $118 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $1.2 billion, $65 million and $50 million, respectively. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $59 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

Fixed Performance Obligations (Applies to AEP, APCo and I&M)

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of September 30, 2025. Fixed performance obligations primarily include electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrants elected to apply the exemption to not disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less. Due to the annual establishment of revenue requirements, transmission revenues are excluded from the table below. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.
Company20252026-20272028-2029After 2029Total
(in millions)
AEP$21.8 $144.1 $49.0 $16.1 $231.0 
APCo4.0 32.2 26.5 11.6 74.3 
I&M1.1 8.8 6.8 2.4 19.1 


196

Contract Assets and Liabilities

Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have material contract assets as of September 30, 2025 and December 31, 2024.

When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheets in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have material contract liabilities as of September 30, 2025 and December 31, 2024.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrant Subsidiaries’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of September 30, 2025 and December 31, 2024. See “Securitized Accounts Receivable - AEP Credit” section of Note 13 for additional information.

The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets:

AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
September 30, 2025$0.1 $143.7 $93.9 $58.2 $65.3 $19.9 $53.0 
December 31, 2024— 131.6 83.7 55.0 63.6 13.0 21.4 

197

CONTROLS AND PROCEDURES

During the third quarter of 2025, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As of September 30, 2025, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of 2025 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
198

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 5 incorporated herein by reference.

Item 1A.  Risk Factors

The 2024 Annual Report includes a detailed discussion of risk factors. Some of the factors, events, and contingencies discussed below or in the 2024 Annual Report may have occurred in the past, and the disclosures below and in the 2024 Annual Report are not representations as to whether or not the factors, events, or contingencies have occurred in the past, but are provided because future occurrences of such factors, events, or contingencies could have a material adverse effect on our business, results of operations, financial condition, future net income or cash flows. Further, the risks and uncertainties described below and in the 2024 Annual Report are not the only ones we face. As of September 30, 2025, the risk factors appearing in the 2024 Annual Report are supplemental and updated as follows:

Changes in U.S. or foreign trade policies, including the imposition of tariffs and other protectionist trade measures, and other factors beyond our control may adversely impact our future net income and cash flows and financial condition.

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. In addition, related geopolitical and domestic political developments, such as existing and potential trade wars, uncertainty regarding changes in trade policy, and other events beyond our control, have increased and may continue to increase levels of political and economic unpredictability globally and the volatility of global financial markets. As a result, prevailing economic conditions may reduce future net income and cash flows and negatively impact financial condition.

Regulation of greenhouse gas emissions could materially increase costs to AEP and its customers or cause some electric generating units to be uneconomical to operate or maintain.

Federal or state laws or regulations may be adopted that could impose new or additional limits on the emissions of greenhouse gases, including, but not limited to, carbon dioxide and methane, from electric generation units using fossil fuels like coal. The potential effects of greenhouse gas emission limits on AEP's electric generation units are subject to significant uncertainties based on, among other things, the timing of the implementation of any new requirements, the required levels of emission reductions, the nature of any market-based or tax-based mechanisms adopted to facilitate reductions, the relative availability of greenhouse gas emission reduction offsets, the development of cost-effective, commercial-scale carbon capture and storage technology and supporting regulations and liability mitigation measures, and the range of available compliance alternatives.

AEP’s results of operations could be materially adversely affected to the extent that new federal or state laws or regulations impose any new greenhouse gas emission limits. Any future limits on greenhouse gas emissions could create substantial additional costs in the form of taxes or emissions allowances, require significant capital investment in carbon capture and storage technology, fuel switching, or the replacement of high-emitting generation facilities with lower-emitting generation facilities and/or could cause AEP to retire generating capacity prior to the end of its estimated useful life. Although AEP typically recovers environmental expenditures, there can be no assurance in the future that AEP can recover such costs which could reduce future net income and cash flows and possibly harm financial condition. Further, real or alleged violations of environmental regulations, including those related to climate change, could reduce future net income and cash flows and possibly harm financial condition.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.  Defaults Upon Senior Securities

None.

199

Item 4.  Mine Safety Disclosures

Not applicable.

Item 5.  Other Information

On August 7, 2025, Phillip R. Ulrich, the Executive Vice President and Chief Human Resources Officer of the Company, entered into a Rule 10b5-1 trading plan intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) of the Securities Exchange Act of 1934. Mr. Ulrich’s Rule 10b5-1 trading plan provides for an aggregate sale of up to 8,860 shares of common stock through May 8, 2026.

During the three months ended September 30, 2025, none of the Company’s directors or other officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act of 1933).

200

Item 6.  Exhibits

The documents designated with an (*) below have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof:

ExhibitDescriptionPreviously Filed as Exhibit to:
AEP‡   File No. 1-3525
*4(a)Supplemental Indenture No. 7 between the Company and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated September 25, 2025, establishing the terms of the Debentures
Form 8-K dated September 23, 2025, Exhibit 4(a)
AEP Texas‡   File No. 3-221643
*4(a)Company Order and Officers’ Certificate between AEP Texas and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated September 24, 2025, establishing terms of the Notes
Form 8-K dated September 22, 2025, Exhibit 4(a)
AEPTCo‡   File No. 3-217143
*4(a)Note Purchase Agreement, dated October 15, 2025, by and among AEP Transmission Company, LLC, the Secretary of Energy acting through the U.S. Department of Energy and the Federal Financing Bank.
Form 8-K dated October 15, 2025, Exhibit 10.1
*4(b)Future Advance Promissory Note of AEP Transmission Company, LLC, dated October 15, 2025.
Form 8-K dated October 15, 2025, Exhibit 10.2
*10.1Loan Guarantee Agreement, dated October 15, 2025, by and between AEP Transmission Company, LLC and the U.S. Department of Energy.
Form 8-K dated October 15, 2025, Exhibit 10.3

The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.
ExhibitDescriptionAEPAEP
Texas		AEPTCoAPCoI&MOPCoPSOSWEPCo
31(a)
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
X
X
X
X
X
X
X
X
31(b)
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
X
X
X
X
X
X
X
X
32(a)
Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
X
X
X
X
X
X
X
X
32(b)
Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
X
X
X
X
X
X
X
X
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201

SIGNATURE


Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.


AMERICAN ELECTRIC POWER COMPANY, INC.



By: /s/ Kate Sturgess
Kate Sturgess
Senior Vice President, Controller and Chief Accounting Officer
(Principal Accounting Officer and Authorized Signatory)



AEP TEXAS INC.
AEP TRANSMISSION COMPANY, LLC
APPALACHIAN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY



By: /s/ Kate Sturgess
Kate Sturgess
Chief Accounting Officer
(Principal Accounting Officer and Authorized Signatory)



Date:  October 29, 2025
202

Source: View Original Filing on SEC EDGAR

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AEP Rankings

#249 Ranked by Market Cap
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AEP Latest News

Oct 29, 2025
AEP Reports Third-Quarter 2025 Operating Earnings, Updated Capital Plan Drives New Long-Term Growth Rate
Oct 22, 2025
AEP Increases Quarterly Dividend to 95 Cents a Share
Oct 16, 2025
AEP Receives U.S. Department of Energy Loan Guarantee to Upgrade 5,000 Miles of Transmission Lines
Aug 4, 2025
I&M, Google Filing to Support Reliability Through Demand Response Structure
Jul 30, 2025
AEP Reports Record Second-Quarter Operating Earnings, Guides to Upper Half of 2025 Guidance Range

AEP Latest SEC Filings

Oct 29, 2025
[8-K] AMERICAN ELECTRIC POWER CO INC Reports Material Event
Oct 23, 2025
[Form 4] AMERICAN ELECTRIC POWER CO INC Insider Trading Activity
Oct 14, 2025
[Form 4] AMERICAN ELECTRIC POWER CO INC Insider Trading Activity
Oct 10, 2025
[144] AMERICAN ELECTRIC POWER CO INC SEC Filing
Oct 3, 2025
[Form 4] AMERICAN ELECTRIC POWER CO INC Insider Trading Activity

AEP Stock Data

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