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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 June 30, 2025
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____
Commission   Registrants;   I.R.S. Employer
File Number   Address and Telephone Number  States of Incorporation   Identification Nos.
         
1-3525   AMERICAN ELECTRIC POWER CO INC. New York   13-4922640
333-221643 AEP TEXAS INC. Delaware 51-0007707
333-217143   AEP TRANSMISSION COMPANY, LLC Delaware   46-1125168
1-3457   APPALACHIAN POWER COMPANY Virginia   54-0124790
1-3570   INDIANA MICHIGAN POWER COMPANY Indiana   35-0410455
1-6543   OHIO POWER COMPANY Ohio   31-4271000
0-343   PUBLIC SERVICE COMPANY OF OKLAHOMA Oklahoma   73-0410895
1-3146   SOUTHWESTERN ELECTRIC POWER COMPANY Delaware   72-0323455
    1 Riverside Plaza, Columbus, Ohio 43215-2373    
    Telephone (614) 716-1000    

Securities registered pursuant to Section 12(b) of the Act:
Registrant   Title of each class   Trading Symbol Name of Each Exchange on Which Registered
American Electric Power Company Inc.   Common Stock, $6.50 par value   AEP The NASDAQ Stock Market LLC
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Yes x No ☐
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).
Yes x No ☐
Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large Accelerated filer x Accelerated filer ☐ Non-accelerated filer ☐
           
Smaller reporting company ☐ Emerging growth company ☐
Indicate by check mark whether AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large Accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer x
           
Smaller reporting company ☐ Emerging growth company ☐  
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
☐
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x
AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.


Number of shares
of common stock
outstanding of the
Registrants as of
July 30, 2025
 
American Electric Power Company, Inc. 534,794,763 
  ($6.50 par value)
AEP Texas Inc. 100 
($0.01 par value)
AEP Transmission Company, LLC (a) NA
Appalachian Power Company 13,499,500 
  (no par value)
Indiana Michigan Power Company 1,400,000 
  (no par value)
Ohio Power Company 27,952,473 
  (no par value)
Public Service Company of Oklahoma 9,013,000 
  ($15 par value)
Southwestern Electric Power Company 3,680 
  ($18 par value)

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


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
June 30, 2025
     
    Page
    Number
Glossary of Terms
     
Forward-Looking Information
     
Part I. FINANCIAL INFORMATION
     
  Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk and Controls and Procedures:
     
American Electric Power Company, Inc. and Subsidiary Companies:  
  Management’s Discussion and Analysis of Financial Condition and Results of Operations
  Condensed Consolidated Financial Statements
     
AEP Texas Inc. and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
Condensed Consolidated Financial Statements
AEP Transmission Company, LLC and Subsidiaries:  
  Management’s Narrative Discussion and Analysis of Results of Operations
  Condensed Consolidated Financial Statements
Appalachian Power Company and Subsidiaries:  
  Management’s Narrative Discussion and Analysis of Results of Operations
  Condensed Consolidated Financial Statements
     
Indiana Michigan Power Company and Subsidiaries:  
  Management’s Narrative Discussion and Analysis of Results of Operations
  Condensed Consolidated Financial Statements
     
Ohio Power Company and Subsidiaries:  
  Management’s Narrative Discussion and Analysis of Results of Operations
  Condensed Consolidated Financial Statements
     
Public Service Company of Oklahoma:  
  Management’s Narrative Discussion and Analysis of Results of Operations
  Condensed Financial Statements
     
Southwestern Electric Power Company Consolidated:  
  Management’s Narrative Discussion and Analysis of Results of Operations
  Condensed Consolidated Financial Statements
     
Index of Condensed Notes to Condensed Financial Statements of Registrants
     
Controls and Procedures


Part II.  OTHER INFORMATION  
         
  Item 1.   Legal Proceedings
  Item 1A.   Risk Factors
  Item 2.   Unregistered Sales of Equity Securities and Use of Proceeds
Item 3.   Defaults Upon Senior Securities
  Item 4.   Mine Safety Disclosures
  Item 5.   Other Information
  Item 6.   Exhibits
         
SIGNATURE    
         
         
This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants.


GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below. 
Term Meaning
     
AEGCo   AEP Generating Company, an AEP electric utility subsidiary.
AEP  
American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit  
AEP Credit, Inc., a consolidated VIE of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East Companies APCo, I&M, KGPCo, KPCo, OPCo and WPCo.
AEP Energy Supply, LLC
A nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
AEP OnSite Partners
A division of AEP Energy Supply, LLC that builds, owns, operates and maintains customer solutions utilizing existing and emerging distributed technologies.
AEP Texas
AEP Texas Inc., an AEP electric utility subsidiary. AEP Texas engages in the transmission and distribution of electric power to retail customers in west, central and southern Texas.
AEP Transmission Holdco / AEPTHCo
  
AEP Transmission Holding Company, LLC, a subsidiary of AEP, an intermediate holding company that owns transmission operations joint ventures and AEPTCo.
AEPEP
AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets.
AEPSC  
American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo
AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AEPTCo Parent AEP Transmission Company, LLC, the holding company of Midwest Transmission Holdings and the State Transcos within the AEPTCo consolidation.
AFUDC Allowance for Equity Funds Used During Construction.
ALJ
 Administrative Law Judge.
AOCI   Accumulated Other Comprehensive Income.
APCo  
Appalachian Power Company, an AEP electric utility subsidiary. APCo engages in the generation, transmission and distribution of electric power to retail customers in the southwestern portion of Virginia and southern West Virginia.
Appalachian Consumer Rate Relief Funding
Appalachian Consumer Rate Relief Funding, LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
APSC Arkansas Public Service Commission.
ARO Asset Retirement Obligations.
ASU Accounting Standards Update.
ATM At-the-Market.
CAA Clean Air Act.
CAMT Corporate Alternative Minimum Tax.
CCR Coal Combustion Residual.
CEO Chief Executive Officer.
CO2
   Carbon dioxide and other greenhouse gases.
CODM Chief Operating Decision Maker.
Cook Plant   Donald C. Cook Nuclear Plant, a two-unit, 2,296 MW nuclear plant owned by I&M.
Cost Recovery Funding
KPCo Cost Recovery Funding, LLC, a wholly-owned subsidiary of KPCo and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to plant retirement costs, deferred storm costs, deferred purchased power expenses, under-recovered purchased power rider costs and issuance-related expenses.
i

Term Meaning
     
CSAPR Cross-State Air Pollution Rule.
CWIP   Construction Work in Progress.
DCC Fuel
DCC Fuel XV, DCC Fuel XVI, DCC Fuel XVII, DCC Fuel XVIII, DCC Fuel XIX, DCC Fuel XX and DCC XXI consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC  
Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. DHLC is a non-consolidated VIE of SWEPCo.
Diversion
Diversion, acquired in December 2024, consists of 201 MWs of wind generation in Texas.
Eastern Region
AEP’s eastern service territory includes the areas where APCo, I&M, KGPCo, KPCo, OPCo and WPCo engage in the generation, transmission and distribution of electric power to customers.
EIS
Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.
ELG Effluent Limitation Guidelines.
ENEC Expanded Net Energy Cost.
ERCOT   Electric Reliability Council of Texas regional transmission organization.
ESA Electric Service Agreement.
ESP  
Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETR
Effective Tax Rate.
ETT
Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADIT Excess accumulated deferred income taxes.
FAC Fuel Adjustment Clause.
FASB   Financial Accounting Standards Board.
Federal EPA United States Environmental Protection Agency.
FERC   Federal Energy Regulatory Commission.
FGD   Flue Gas Desulfurization or scrubbers.
FIP Federal Implementation Plan.
FTR
Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP   Generally Accepted Accounting Principles in the United States of America.
GHG Greenhouse gas.
G&M
Generation & Marketing.
I&M  
Indiana Michigan Power Company, an AEP electric utility subsidiary. I&M engages in the generation, transmission and distribution of electric power to retail customers in northern and eastern Indiana and southwestern Michigan.
IMTCo
AEP Indiana Michigan Transmission Company, Inc.
IRS   Internal Revenue Service.
ITC Investment Tax Credit.
IURC Indiana Utility Regulatory Commission.
KGPCo
Kingsport Power Company, an AEP electric utility subsidiary. KGPCo provides electric service to retail customers in Kingsport, Tennessee and eight neighboring communities in northeastern Tennessee.
KPCo  
Kentucky Power Company, an AEP electric utility subsidiary. KPCo engages in the generation, transmission and distribution of electric power to retail customers in eastern Kentucky.
KPSC Kentucky Public Service Commission.
ii

Term Meaning
     
KWh
Kilowatt-hour.
LPSC  
Louisiana Public Service Commission.
MATS
Mercury and Air Toxic Standards.
Midwest Transmission Holdings
Midwest Transmission Holdings, LLC, a subsidiary of AEPTCo Parent that owns all of the issued and outstanding stock of IMTCo and OHTCo.
MISO  
Midcontinent Independent System Operator.
Mitchell Plant
A two unit, 1,560 MW coal-fired power plant located in Moundsville, West Virginia. The plant is jointly owned by KPCo and WPCo.
MMBtu  
Million British Thermal Units.
MPSC
Michigan Public Service Commission.
MTM  
Mark-to-Market.
MW  
Megawatt.
MWh  
Megawatt-hour.
NAAQS
National Ambient Air Quality Standards.
NCWF
North Central Wind Energy Facilities, a joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,484 MWs of wind generation.
NMRD
New Mexico Renewable Development, LLC.
Nonutility Money Pool  
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NOLC
Net Operating Loss Carryforward.
NOx
 Nitrogen Oxide.
OCC   Corporation Commission of the State of Oklahoma.
ODEQ Oklahoma Department of Environmental Quality.
OHTCo
AEP Ohio Transmission Company, Inc.
OPCo  
Ohio Power Company, an AEP electric utility subsidiary. OPCo engages in the transmission and distribution of electric power to retail customers in Ohio.
OPEB   Other Postretirement Benefits.
OTC   Over-the-counter.
OVEC   Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent
American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PFD
Proposal for Decision.
PJM   Pennsylvania – New Jersey – Maryland regional transmission organization.
PLR Private Letter Ruling.
PM   Particulate Matter.
PPA Power Purchase Agreement.
PSA
Purchase and Sale Agreement.
PSO  
Public Service Company of Oklahoma, an AEP electric utility subsidiary. PSO engages in the generation, transmission and distribution of electric power to retail customers in eastern and southwestern Oklahoma.
PTC
Production Tax Credit.
PUCO   Public Utilities Commission of Ohio.
PUCT   Public Utility Commission of Texas.
Registrant Subsidiaries  
AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants
SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
iii

Term Meaning
     
Restoration Funding
AEP Texas Restoration Funding, LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey.
Risk Management Contracts  
Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
A generation plant, jointly owned by AEGCo and I&M, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.
ROE Return on Equity.
RPM Reliability Pricing Model.
RTO  
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine  
Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo.
SEC U.S. Securities and Exchange Commission.
SIP State Implementation Plan.
SNF   Spent Nuclear Fuel.
SO2
   Sulfur Dioxide.
SPP  
Southwest Power Pool regional transmission organization.
SSO  
Standard service offer.
State Transcos
AEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP’s existing utility operating companies.
Storm Recovery Funding
SWEPCo Storm Recovery Funding, LLC, a wholly-owned subsidiary of SWEPCo and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Louisiana.
SWEPCo  
Southwestern Electric Power Company, an AEP electric utility subsidiary. SWEPCo engages in the generation, transmission and distribution of electric power to retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas.
SWTCo
AEP Southwestern Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
TA
Transmission Agreement, effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
Tax Reform
On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
T&D
Transmission and Distribution Utilities.
Transition Funding  
AEP Texas Central Transition Funding III, LLC, a wholly-owned subsidiary of AEP Texas and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to restructuring legislation in Texas.
Transource Energy
Transource Energy, LLC, a consolidated VIE formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. Transource Energy is 86.5% owned by AEP.
Turk Plant  
John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
UPA
Unit Power Agreement.
Utility Money Pool  
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
Valley Link
Valley Link Transmission Company, LLC, a holding company formed by Transource Energy, affiliates of Dominion Energy and FirstEnergy in 2024.
VIE
Variable Interest Entity.
Virginia SCC  
Virginia State Corporation Commission.
VIU
Vertically Integrated Utilities.
iv

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

FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements, and for the Registrants other than Parent, this report contains forward looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Part I – Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this quarterly report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
• Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.
• The economic impact of increased global conflicts and trade tensions, and the adoption or expansion of economic sanctions, tariffs, trade restrictions or changes in trade policy.
• Inflationary or deflationary interest rate trends.
• New legislation adopted in the states in which we operate that alters the regulatory framework or that prevents the timely recovery of costs and investments.
• Volatility and disruptions in financial markets precipitated by any cause, including fiscal and monetary policy, turmoil related to federal budget or debt ceiling matters or instability in the banking industry; particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
• The availability and cost of funds to finance working capital and capital needs, particularly (a) if expected sources of capital such as proceeds from the sale of assets, subsidiaries and tax credits and anticipated securitizations do not materialize or do not materialize at the level anticipated, and (b) during periods when the time lag between incurring costs and recovery is long and the costs are material.
• Changing demand for electricity, including large load contractual commitments for interconnection.
• The risks and uncertainties associated with wildfires, including damages caused by wildfires, the extent of each Registrant’s liability in connection with wildfires, investigations and outcomes associated with legal proceedings, demands or similar actions, inability to recover wildfire costs through insurance or through rates and the impact on financial condition and the reputation of each Registrant.
• The impact of extreme weather conditions, natural disasters and catastrophic events such as storms, wildfires and drought conditions that pose significant risks including potential litigation and the inability to recover significant damages and restoration costs incurred.
• Limitations or restrictions on the amounts and types of insurance available to cover losses that might arise in connection with natural disasters, wildfires or operations.
• The cost of fuel and its transportation, the creditworthiness and performance of parties who supply and transport fuel and the cost of storing and disposing of used fuel, including coal ash and SNF.
• The availability of fuel and necessary generation capacity and the performance of generation plants.
• The ability to recover fuel and other energy costs through regulated or competitive electric rates.
• The ability to build or acquire generation (including from renewable sources), transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) to meet the demand for electricity at acceptable prices and terms, including favorable tax treatment, cost caps imposed by regulators and other operational commitments to regulatory commissions and customers for generation projects, to recover all related costs and to earn a reasonable return.
• The disruption of AEP’s business operations due to impacts of economic or market conditions, costs of compliance with potential government regulations, electricity usage, supply chain issues, customers, service providers, vendors and suppliers caused by pandemics, natural disasters or other events.
• New legislation, litigation or government regulation, including changes to tax laws and regulations, oversight of nuclear generation, energy commodity trading and new or modified requirements related to emissions of sulfur, nitrogen, mercury, carbon, soot or PM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.
• The impact of tax legislation or associated Department of Treasury guidance, including potential changes to existing tax incentives, on capital plans, results of operations, financial condition, cash flows or credit ratings.
• The risks before, during and after generation of electricity associated with the fuels used or the by-products and wastes of such fuels, including coal ash and SNF.
• Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
vi

• Resolution of litigation or regulatory proceedings or investigations.
• The ability to efficiently manage and recover operation, maintenance and development project costs.
• Prices and demand for power generated and sold at wholesale.
• Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
• The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
• Volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas.
• The impact of changing expectations and demands of customers, regulators, investors and stakeholders, including development, adoption, and use of artificial intelligence by us, our customers and our third party vendors and evolving expectations related to environmental, social and governance concerns.
• Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP.
• Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
• Actions of rating agencies, including changes in the ratings of debt.
• The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB and nuclear decommissioning trust funds and a captive insurance entity and the impact of such volatility on future funding requirements.
• Accounting standards periodically issued by accounting standard-setting bodies.
• Other risks and unforeseen events, including wars and military conflicts, the effects of terrorism (including increased security costs), embargoes, cybersecurity threats, labor strikes impacting material supply chains, global information technology disruptions and other catastrophic events.
• The ability to attract and retain the requisite work force and key personnel.
The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made.  The Registrants expressly disclaim any obligation to update any forward-looking information, except as required by law.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the Annual Report on Form 10-K for the fiscal year ended December 31, 2024 (the “2024 Annual Report”) and in Part II of this report.

The Registrants may use AEP’s website as a distribution channel for material company information. Financial and other important information regarding the Registrants is routinely posted on and accessible through AEP’s website at www.aep.com/investors/. In addition, you may automatically receive email alerts and other information about the Registrants when you enroll your email address by visiting the “Email Alerts” section at www.aep.com/investors/.

Company Website and Availability of SEC Filings

Our principal corporate website address is www.aep.com. Information on our website is not incorporated by reference herein and is not part of this Form 10-Q. We make available free of charge through our website our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such documents are electronically filed with, or furnished to, the SEC. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding AEP.
vii

PART I.  FINANCIAL INFORMATION

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

AEP CONSOLIDATED RESULTS OF OPERATIONS

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•The favorable impact from the receipt of a June 2025 FERC order related to the treatment of NOLCs in transmission formula rates. See “June 2025 FERC Orders on NOLCs in Transmission Formula Rates” section below for additional information.
•A revenue refund provision recorded in 2024 associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.
•An increase in operating expenses recorded in 2024 due to the Federal EPA’s revised CCR rule finalized in 2024.
•An increase in operating expenses recorded in 2024 due to the voluntary severance program that occurred in the second quarter of 2024.
•Favorable rate proceedings in AEP’s various jurisdictions.

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

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

•The favorable impact from the receipt of a June 2025 FERC order related to the treatment of NOLCs in transmission formula rates. See “June 2025 FERC Orders on NOLCs in Transmission Formula Rates” section below for additional information.
•A revenue refund provision recorded in 2024 associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.
•An increase in operating expenses recorded in 2024 due to the Federal EPA’s revised CCR rule finalized in 2024.
•An increase in operating expenses recorded in 2024 due to the voluntary severance program that occurred in the second quarter of 2024.
•An increase in sales volumes driven by favorable weather.
•Favorable rate proceedings in AEP’s various jurisdictions.

These increases were partially offset by:

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

See “Results of Operations” section for additional information by operating segment.
1

Non-GAAP Financial Measures

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

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

Reconciliation of Reported GAAP Earnings to Operating Earnings

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

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

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

(a)Excluding tax related adjustments, all items presented in the table are tax adjusted at the statutory rate unless otherwise noted.
(b)Represents the impact of mark-to-market economic hedging activities.
(c)Represents the impact of the FERC NOLC Order for years 2021-2024.
(d)Represents the impact of the remeasurement of Excess ADIT in Michigan.
(e)Represents a provision for revenue refunds on certain capitalized costs associated with the Turk Plant.
(f)Represents the loss on the expected sale of AEP OnSite Partners.
(g)Represents employee severance charges.
(h)Represents the impact of the Federal EPA Revised CCR Rule.
2

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

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

(a)Excluding tax related adjustments, all items presented in the table are tax adjusted at the statutory rate unless otherwise noted.
(b)Represents the impact of mark-to-market economic hedging activities.
(c)Represents an adjustment to the estimated loss on the sale of AEP OnSite Partners as a result of the contractual working capital true-up.
(d)Represents the estimated reduction in regulatory assets for OVEC-related purchased power costs as a result of approved legislation in Ohio in April 2025.
(e)Represents the impact of the FERC NOLC Order for years 2021-2024.
(f)Represents the impact of the remeasurement of Excess ADIT in Arkansas and Michigan.
(g)Represents the impact of receiving IRS PLRs related to NOLCs in retail ratemaking on I&M, PSO and SWEPCo. Amount includes a reduction in Excess ADIT and activity related to prior periods.
(h)Represents the impact of a disallowance recorded at SWEPCo on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.
(i)Represents a provision for revenue refunds on certain capitalized costs associated with the Turk Plant.
(j)Represents the loss on the expected sale of AEP OnSite Partners.
(k)Represents employee severance charges.
(l)Represents the impact of the Federal EPA Revised CCR Rule.





3

RECENT DEVELOPMENTS AND TRANSACTIONS

NOLCs in Transmission Formula Rates - June 2025 FERC Orders

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

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

(a)Primarily represents the reversal of revenue refund provisions for years 2021-2025, partially offset by an increase in affiliated transmission expenses.
(b)Primarily relates to a $384 million remeasurement of Excess ADIT regulatory liabilities, partially offset by $71 million of tax expense on favorable pretax income.
(c)The noncontrolling interest relates to IMTCo and OHTCo. See “Noncontrolling Interest in OHTCo and IMTCo” section of Note 6 for additional information.
(d)Includes KGPCo, KPCo, OPCo and WPCo.

NOLCs in Retail Jurisdictions - IRS PLRs

AEP’s utility subsidiaries have made rate filings with state commissions to transition to stand-alone treatment of NOLCs in retail ratemaking. In April 2024, supportive PLRs for certain retail jurisdictions were received from the IRS, effective March 2024. The PLRs concluded NOLCs on a stand-alone ratemaking basis should be included in rate base and should also be included in the computation of Excess ADIT regulatory liabilities to be refunded to customers. Based on this conclusion, I&M, PSO and SWEPCo recognized regulatory assets related to revenue requirement amounts to be collected from customers, reduced Excess ADIT regulatory liabilities and recorded favorable impacts to net income in the first quarter of 2024 as shown in the table below:

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

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


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

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

(a)AEP Texas and OPCo do not have NOLCs on a stand-alone basis.
(b)Pending in 2024 West Virginia Base Rate Case.
(c)Awaiting receipt of jurisdiction specific IRS PLR.
(d)Pending in 2025 Arkansas Base Rate Case.

Beginning in the second quarter of 2024 and continuing until the NOLC revenue requirement is in rates, AEP is recognizing additional regulatory assets related to revenue requirement amounts to be collected from customers. As of June 30, 2025, AEP has NOLC regulatory assets of $114 million on its balance sheet.

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

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

PSO New Generation Resources

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

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

Kentucky Securitization

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

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New Legislation

Ohio Legislation

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

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

Texas Legislation

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

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

Oklahoma Legislation

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

Federal Tax Legislation

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

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

Valley Link Investment (Applies to AEP and Transource Energy)

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

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

Fuel Cell Agreement

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

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

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Customer Demand

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

7994
(a)Percentage change for the three months ended June 30, 2025 as compared to the three months ended June 30, 2024.
(b)Percentage change for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024.

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

8796093143886
(a)As presented in the 2024 AEP 10-K: Forecasted percentage change for the year ended December 31, 2025 compared to the year ended December 31, 2024.
(b)Revised: Forecasted percentage change for the year ended December 31, 2025 compared to the year ended December 31, 2024. The revised 2025 forecast reflects year-to-date actual results plus six months of forecasted values based on underlying economic and demographic trends.

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Inflation, Tariffs on International Trade and Supply Chain Disruption

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

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

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

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

Large Load/Data Center Tariffs

Certain AEP utility subsidiaries have made rate filings with state commissions to establish new tariffs for data centers and other large load customers. These new tariffs are generally designed to extend the duration of ESAs, implement higher minimum demand charges and address changes in contract capacity and termination of service. The table below provides a summary of the status of these new data center and large load tariffs.
Jurisdiction Large Load Tariff Status Customer Eligibility
Indiana Industrial Power Approved New load of 150 MW or more/70 MW for individual site
Kentucky Industrial General Service Approved New commercial or industrial load of 150 MW or more
Ohio Data Center Approved New data center load of 25 MW or more
Virginia Large Power Service Pending New load of 150 MW or more/100 MW for individual site
West Virginia Large Capacity/Industrial Power Approved New load of 200 MW or more

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

New Generation to Support Reliability

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

Significant Approved Renewable Generation Filings

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

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

(a)APCo has issued notice to proceed for the construction of all 344 MWs of wind capacity.
(b)PSO has issued notices to proceed for the construction of two wind facilities for a total capacity of 418 MWs. These facilities are part of the approved projects contemplated within PSO’s 568 MWs of total new renewable generation.
(c)The recently enacted OBBBA legislation is not expected to impact the qualification of federal tax incentives for these generation facilities.

Natural Gas Generation

In December 2024, SWEPCo filed an application for a Certificate of Convenience and Necessity (CCN) with the APSC, LPSC and PUCT for the construction of the Hallsville Natural Gas Plant (450 MWs) and the fuel conversion of Welsh Plant, Units 1 and 3 to natural gas. In the application for the CCN, SWEPCo seeks to site the Hallsville Natural Gas Plant at the location of the now-retired Pirkey Power Plant. If approved, the projects will help SWEPCo address increasing SPP capacity requirements. SWEPCo estimates the combined capital cost of these projects is approximately $723 million and the projects would be placed in service between November 2027 and May 2028.

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

Significant Generation Requests for Proposal (RFP)

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

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

(a)RFP is seeking 1,500 MW of SPP accredited capacity and associated energy through an all-source solicitation.
(b)RFP is seeking up to 4,000 MW (cumulatively) from intermittent (wind, solar), non-intermittent (dispatchable), and emerging technology resources.
(c)RFP is seeking wind, solar, stand-alone battery energy storage systems and Renewable Energy Certificates.
(d)RFP is seeking 800 MW of wind, solar, and/or co-located or stand-alone battery energy storage systems PSAs.
(e)RFP is seeking 300 MW of wind, solar, hydro, or geothermal PPAs.


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Capacity Purchase Agreements

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

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

Regulatory Matters - Utility Rates and Rate Proceedings

The Registrants are involved in rate cases and other proceedings with their regulatory commissions in order to establish fair and appropriate electric service rates to recover their costs and earn a fair return on their investments.  Depending on the outcomes, these rate cases and proceedings can have a material impact on results of operations, cash flows and financial condition.

The following table summarizes the Registrants’ pending base rate case proceedings. See Note 4 - Rate Matters for additional information.
Annual
Filing Base Revenue Requested
Company Jurisdiction Date Increase Request ROE
(in millions)
APCo West Virginia November 2024 $ 224.0  10.8%
SWEPCo Arkansas March 2025 114.0  10.9%
OPCo Ohio May 2025 97.4  10.9%

Other Significant Regulatory Matters

2025 West Virginia Securitization Filing

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

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

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


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2025 Virginia Securitization Legislation and Securitization Filing

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

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

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

Claims for Indemnification Made by Owners of the Gavin Power Station

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

ENVIRONMENTAL ISSUES

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

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

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


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Impact of Environmental Compliance on the Generating Fleet

The rules and environmental control requirements discussed below will have a material impact on AEP’s operations.  As of June 30, 2025, AEP owned generating capacity of approximately 24,400 MWs, of which approximately 10,700 MWs were coal-fired.   In April 2024, the Federal EPA announced four major new rules directed at fossil-fuel electric generation facilities. Management continues to evaluate the impacts of these rules on the plans for the future of AEP’s generating fleet, in particular, the economic feasibility of making the requisite environmental investments in AEP’s fossil generation fleet. AEP continues to refine the cost estimates of complying with these rules to identify the best alternative for ensuring compliance with all of the rules while meeting AEP’s obligations to provide reliable and affordable electricity.

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

Clean Air Act Requirements

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

National Ambient Air Quality Standards

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

Areas with air quality that does not meet the new standard will be designated by the Federal EPA as “nonattainment,” which will trigger an obligation for states to revise their SIPs to include additional requirements, resulting in further emission reductions to ensure that the new standard will be met. Areas around some of AEP’s generating facilities may be deemed nonattainment, which may require those facilities to install additional pollution controls or to implement operational constraints. The nonattainment designations by the Federal EPA and the subsequent SIP revisions by the affected states will take some time to complete; therefore, management cannot reasonably estimate the impact on AEP’s operations, cash flows, net income or financial condition.

Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR) in 2005, which could require power plants and other facilities to install best available retrofit technology to address regional haze in federal parks and other protected areas. CAVR is implemented by the states, through SIPs, or by the Federal EPA, through FIPs. In 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs. Petitions for review of the final rule revisions were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In early 2018, the Federal EPA announced plans to revisit aspects of the final rule raised by petitioners in petitions for administrative reconsideration, and the court granted the Federal EPA’s motion to hold the litigation in abeyance.

The Federal EPA disapproved portions of the Texas regional haze SIP and finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOX regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations. Environmental groups filed challenges to these various rulemakings in district courts in the Fifth Circuit and the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and intervened in the Fifth Circuit litigation in support of the Federal EPA. In July 2024, the U.S. District Court for the District of Columbia Circuit entered a consent decree setting deadlines for the Federal EPA to rule on Regional Haze SIPs for 32 states, including Texas. In September 2024, the Federal EPA signed a proposed rule to partially approve and partially disapprove the Texas SIP revision. In May 2025, the Federal EPA proposed to 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.
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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.
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These proposals have not been finalized. On July 29, 2025, the Federal EPA announced that it would be proposing a repeal of the 2009 Endangerment Finding, which determined that greenhouse gas emissions endanger public health and welfare. The 2009 Endangerment Finding is the basis of Federal EPA’s authority to regulate greenhouse gas emissions under the Clean Air Act and was used to first regulate motor vehicle emissions. We are evaluating the Federal EPA’s proposed repeal of the 2009 Endangerment Finding and its impact on Federal EPA’s authority to regulate greenhouse gas emissions from electric generators. Management cannot predict the outcome of the current litigation or Federal EPA’s proposed actions related to the rule or the Endangerment Finding and any subsequent litigation that may result. Excessive costs to comply with environmental regulations have led to the announcement of early plant closures across the country. The Federal EPA’s 2024 GHG rules, and suite of other new rules issued simultaneously and discussed below, are directed at the fossil-fuel fired electric utility industry and could force AEP to close additional coal-fired generation facilities earlier than their estimated useful life, if those rules remain in place. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.

MATS Rule

In April 2024, the Federal EPA issued a revised MATS rule for power plants. The rule includes a more stringent standard for emissions of filterable PM for coal-fired electric generating units, as well as a new mercury standard for lignite-fired electric generating units. The rule also requires the installation and operation of continuous emissions monitors for PM. Several states and other parties have challenged the rule in the United States Court of Appeals for the District of Columbia Circuit, but management cannot predict the outcome of the litigation. The litigation is being held in abeyance while the current Presidential administration evaluates the rule. In April 2025, the President issued a Proclamation exempting certain generation sources from the requirement to comply with the 2024 MATS rule for two years beyond the rule’s compliance date. In June 2025, the Federal EPA proposed to repeal the 2024 MATS rule and revert to the 2012 MATS rule emission standards. Management does not anticipate any significant challenges complying with the 2024 MATS rule, should the proposed repeal not be finalized.

CCR Rule

The Federal EPA’s CCR Rule regulates the disposal and beneficial re-use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants.  As originally promulgated, the rule applied to active and inactive CCR landfills and surface impoundments at facilities of active electric utility or independent power producers. In April 2024, the Federal EPA finalized revisions to the CCR Rule to expand the scope of the rule to include inactive impoundments at inactive facilities (“legacy CCR surface impoundments”) as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land (“CCR management units”). In March 2025, the Federal EPA announced plans to make changes to the CCR Rule and to work with states to implement future CCR requirements. See “Federal EPA’s Revised CCR Rule” section in Note 5 for additional information.

Clean Water Act Regulations

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

In April 2024, the Federal EPA finalized further revisions to the ELG rule that establish a zero liquid discharge standard for FGD wastewater, bottom ash transport water, and managed combustion residual leachate, as well as more stringent discharge limits for unmanaged combustion residual leachate. The revised rule provides a new compliance alternative that would eliminate the need to install zero liquid discharge systems for facilities that comply with the 2020 rule’s control technology requirements and commit by December 31, 2025, to retire by 2034. Management is evaluating the compliance alternatives in the rule, taking into consideration the requirements of the other new rules and their combined impacts to operations. Several appeals have been filed with various federal courts challenging the 2024 ELG rule. SWEPCo has also challenged the rule, by filing a joint appeal with a utility trade association in which AEP participates. The various appeals have been consolidated before the United States Court of Appeals for the Eighth Circuit. SWEPCo and the utility trade association filed a motion to stay the rule during the litigation. In October 2024, the court denied the motion. The litigation challenging the ELG Rule is being held in abeyance while the new administration evaluates the rule.
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In March 2025, the Federal EPA announced plans to reconsider the standards established by the 2024 ELG rule. Management cannot predict the outcome of the litigation or any further actions by the Federal EPA related to the ELG rule.

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

Impact of Environmental Regulation on Coal-Fired Generation

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

The table below summarizes the net book value, as of June 30, 2025, of generating facilities retired or planned for early retirement in advance of the retirement date currently authorized for ratemaking purposes:
Company Plant Net
Investment (a)		 Accelerated Depreciation Regulatory Asset Actual/Projected
Retirement
Date		 Current Authorized
Recovery
Period		 Annual Depreciation (b)
(in millions) (in millions)
PSO Northeastern Plant, Unit 3 $ 79.8  $ 204.7  2026 (c) $ 16.7 
SWEPCo Pirkey Plant —  132.6  (d) 2023 (e) — 
SWEPCo Welsh Plant, Units 1 and 3 300.9  192.7  2028 (f) (g) 45.9 

(a)Net book value, including CWIP, excluding cost of removal and materials and supplies.
(b)These amounts represent the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040. In April 2025, PSO and ODEQ finalized a second amended regional haze agreement that would allow continued operation of the Northeastern Plant, Unit 3, on natural gas, through May 31, 2041. This agreement is contingent upon approval by the Federal EPA in the form of a revised SIP. ODEQ is in the process of preparing a SIP submission for the Federal EPA’s review and approval.
(d)Represents Arkansas and Texas jurisdictional share.
(e)As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo is seeking recovery of the $37 million Arkansas jurisdictional share and a weighted average cost of capital carrying charge in the base rate case filed in March 2025. The Texas share of the Pirkey Plant will be addressed in SWEPCo’s next base rate case. See the “Regulated Generating Units” section of Note 4 for additional information.
(f)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028. In December 2024, SWEPCo filed an application for a Certificate of Convenience and Necessity (CCN) with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively.
(g)Welsh Plant, Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Welsh Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

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

AEP’s Reportable Segments

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

•Vertically Integrated Utilities
•Transmission and Distribution Utilities
•AEP Transmission Holdco
•Generation & Marketing

The remainder of AEP’s activities are presented as Corporate and Other, which is not considered a reportable segment. See Note 8 - Business Segments for additional information on AEP’s segments.

The following discussion of AEP’s results of operations by operating segment provides a comparison of earnings (loss) attributable to AEP Common Shareholders for the three months ended and six months ended June 30, 2025 as compared to the three months ended and six months ended June 30, 2024 in accordance with GAAP. For AEP’s Vertically Integrated Utilities and Transmission and Distribution Utilities segments and Registrant Subsidiaries within these segments, the results include revenues from rate rider mechanisms designed to recover fuel, purchased power and other recoverable expenses such that the revenues and expenses associated with these items generally offset and do not affect Earnings Attributable to AEP Common Shareholders. For additional information regarding the financial results for the three and six months ended June 30, 2025 and 2024, see the discussions of Results of Operations by Subsidiary Registrant.

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

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

See Note 8 - Business Segments for additional information on Earnings (Loss) Attributable to AEP Common Shareholders by segment.

Heating Degree Days and Cooling Degree Days

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.  In general, degree day changes in the Eastern Region have a larger effect on revenues than changes in the Western Region due to the relative size of the two regions and the number of customers within each region.

The actual heating degree days are calculated on a 55-degree temperature base and the actual cooling degree days are calculated on a 65-degree temperature base for Registrant Subsidiaries except AEP Texas. AEP Texas’ actual heating degree days are calculated on a 55-degree temperature base and actual cooling degree days are calculated on a 70-degree temperature base. Due to the recent more volatile weather, effective in January 2025, the calculation methodology for heating degree days and cooling degree days was changed from a daily minimum/maximum average temperature over a thirty-year period to a daily hourly average temperature over a twenty-year period. This change did not have a material impact on the Registrants’ discussion of weather-related usage.
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VERTICALLY INTEGRATED UTILITIES

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

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


Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2025 2024 2025 2024
  (in degree days)
Eastern Region        
Actual – Heating
 118  81  1,735  1,302 
Normal – Heating
 133  138  1,700  1,743 
Actual – Cooling
 374  473  382  474 
Normal – Cooling
 348  339  352  343 
Western Region        
Actual – Heating
 21  5  966  743 
Normal – Heating
 34  33  903  909 
Actual – Cooling
 772  921  831  976 
Normal – Cooling
 738  709  771  739 
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Vertically Integrated Utilities
Reconciliation of 2024 to 2025 Earnings Attributable to AEP Common Shareholders
(in millions)
 
Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2024 Earnings Attributable to AEP Common Shareholders $ 65.7  $ 626.5 
   
Changes in Revenues:  
Retail Revenues 286.6  480.9 
Off-system Sales 55.9  62.3 
Transmission Revenues 62.9  71.9 
Other Revenues (9.2) (29.0)
Total Change in Revenues 396.2  586.1 
   
Changes in Expenses and Other:  
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (49.7) (126.0)
Other Operation and Maintenance (28.6) (26.7)
Asset Impairments and Other Related Charges 13.4  13.4 
Depreciation and Amortization (45.1) (106.7)
Taxes Other Than Income Taxes 10.0  16.1 
Other Income (0.9) — 
Allowance for Equity Funds Used During Construction 3.2  7.9 
Non-Service Cost Components of Net Periodic Pension Cost (3.6) (11.8)
Interest Expense (10.8) (54.3)
Total Change in Expenses and Other (112.1) (288.1)
   
Income Tax Expense 82.7  (168.3)
Equity Earnings of Unconsolidated Subsidiary —  (0.1)
Net Income Attributable to Noncontrolling Interests 0.2  0.7 
2025 Earnings Attributable to AEP Common Shareholders $ 432.7  $ 756.8 

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Retail Revenues increased $287 million primarily due to the following:
•A $160 million increase due to a revenue refund provision recorded in 2024 associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.
•A $64 million increase in base rate revenues at I&M and PSO.
•A $40 million increase in weather-normalized revenues primarily in the residential and commercial classes, partially offset by a decrease in the industrial class.
•A $38 million increase in rider revenues across all companies.
•A $27 million increase in fuel revenues primarily due to increases at APCo and I&M, partially offset by a decrease at PSO.
These increases were partially offset by:
•A $42 million decrease in weather-related usage primarily in the residential class driven by an 18% decrease in cooling degree days.
•A $22 million decrease due to regulatory provisions for refund at I&M.
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•Off-system Sales increased $56 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales at I&M.
•Transmission Revenues increased $63 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•Other Revenues decreased $9 million primarily due to revenues from a customer project to enhance transmission resiliency in 2024 at PSO.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation increased $50 million primarily due to an increase at I&M, partially offset by decreases at APCo and PSO.
•Other Operation and Maintenance expenses increased $29 million primarily due to the following:
•A $53 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $22 million increase in distribution expenses primarily due to vegetation management costs.
•A $17 million increase in PJM and SPP transmission expenses.
•A $6 million increase in nuclear expenses at Cook Plant.
These increases were partially offset by:
•A $76 million decrease in employee-related expenses due to the voluntary severance program that occurred in the second quarter of 2024.
•Asset Impairments and Other Related Charges decreased $13 million due to the Federal EPA’s revised CCR rules finalized in 2024.
•Depreciation and Amortization expenses increased $45 million primarily due to a higher depreciable base at APCo, I&M and SWEPCo.
•Taxes Other Than Income Taxes decreased $10 million primarily due to lower business and occupation taxes at APCo.
•Interest Expense increased $11 million primarily due to a prior year deferral of expenses as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.
•Income Tax Expense decreased $83 million primarily due to the following:
•A $114 million decrease due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $30 million decrease due to an increase in PTCs.
These decreases were partially offset by:
•A $60 million increase due to an increase in pretax book income.

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

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

•Retail Revenues increased $481 million primarily due to the following:
•A $160 million increase due to a revenue refund provision recorded in 2024 associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.
•A $131 million increase in base rate revenues at I&M and PSO.
•A $110 million increase in rider revenues across all companies.
•A $60 million increase in fuel revenues primarily due to increases at APCo and I&M, partially offset by a decrease at PSO.
•A $41 million increase in weather-related usage primarily in the residential class driven by a 32% increase in heating degree days.
•A $28 million increase in weather-normalized revenues primarily in the residential and commercial classes, partially offset by a decrease in the industrial class.
These increases were partially offset by:
•A $71 million decrease due to regulatory provisions for refund at I&M.
•Off-system Sales increased $62 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales at I&M.
•Transmission Revenues increased $72 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•Other Revenues decreased $29 million primarily due to revenues from a customer project to enhance transmission resiliency in 2024 at PSO, a decrease in sales of renewable energy credits at APCo and I&M and a decrease in River Transportation Division (RTD) barging revenues at I&M.


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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $126 million primarily due to increases at I&M and SWEPCo, partially offset by decreases at APCo and PSO.
•Other Operation and Maintenance expenses increased $27 million primarily due to the following:
•A $53 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $34 million increase in PJM and SPP transmission expenses.
•A $32 million increase in distribution expenses primarily due to vegetation management costs.
These increases were partially offset by:
•A $76 million decrease in employee-related expenses due to the voluntary severance program that occurred in the second quarter of 2024.
•A $14 million decrease to a disallowance recorded at SWEPCo on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.
•Asset Impairments and Other Related Charges decreased $13 million due to the Federal EPA’s revised CCR rules finalized in 2024.
•Depreciation and Amortization expenses increased $107 million primarily due to the following:
•A $65 million increase primarily due to a higher depreciable base at APCo, I&M and SWEPCo.
•A $9 million increase due to a prior year deferral of Excess ADIT as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs at I&M.
•An $8 million increase at SWEPCo due to the amortization of the Storm Recovery Funding securitized assets.
•A $5 million increase in regulatory reserves related to Nuclear PTCs at I&M.
•Taxes Other Than Income Taxes decreased $16 million primarily due to lower business and occupation taxes at APCo.
•Allowance for Equity Funds Used During Construction increased $8 million primarily due to higher CWIP.
•Non-Service Cost Components of Net Periodic Benefit Cost increased $12 million primarily due to an increase in loss amortization and discount rates from 2024 to 2025.
•Interest Expense increased $54 million primarily due to a prior year deferral of expenses as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.
•Income Tax Expense increased $168 million primarily due to the following:
•A $212 million increase due to a reduction in Excess ADIT regulatory liabilities at I&M, PSO and SWEPCo as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking recorded in 2024.
•A $57 million increase due to an increase in pretax book income.
•A $32 million increase due to a reduction in Excess ADIT regulatory liabilities as a result of the APSC’s denial of SWEPCo’s request to allow the merchant portion of the Turk Plant to serve Arkansas customers recorded in 2024.
These increases were partially offset by:
•A $114 million decrease due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $32 million decrease due to an increase in PTCs.

22

TRANSMISSION AND DISTRIBUTION UTILITIES

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

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


Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2025 2024 2025 2024
  (in degree days)
Eastern Region        
Actual – Heating
 170  110  2,077  1,573 
Normal – Heating
 173  181  1,993  2,052 
Actual – Cooling
 336  422  342  422 
Normal – Cooling
 323  306  325  309 
Western Region        
Actual – Heating
 4  1  296  162 
Normal – Heating
 4  3  208  198 
Actual – Cooling
 992  1,198  1,153  1,344 
Normal – Cooling
 909  949  1,021  1,086 
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Transmission and Distribution Utilities
Reconciliation of 2024 to 2025 Earnings Attributable to AEP Common Shareholders
(in millions)
   
Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2024 Earnings Attributable to AEP Common Shareholders $ 146.8  $ 297.1 
   
Changes in Revenues:  
Retail Revenues 38.2  64.4 
Off-system Sales 12.9  25.8 
Transmission Revenues (6.2) 14.2 
Other Revenues (30.6) (53.8)
Total Change in Revenues 14.3  50.6 
   
Changes in Expenses and Other:  
Purchased Electricity for Resale
 (3.9) 7.9 
Purchased Electricity from AEP Affiliates 10.7  41.4 
Other Operation and Maintenance (20.4) (78.3)
Asset Impairments and Other Related Charges 52.9  52.9 
Depreciation and Amortization 25.4  45.0 
Taxes Other Than Income Taxes 18.7  4.3 
Other Income (2.6) (2.0)
Allowance for Equity Funds Used During Construction (0.2) 4.2 
Non-Service Cost Components of Net Periodic Benefit Cost 1.1  0.6 
Interest Expense (4.2) (19.6)
Total Change in Expenses and Other 77.5  56.4 
   
Income Tax Expense (15.5) (17.8)
Equity Earnings (Loss) of Unconsolidated Subsidiary 0.8  2.2 
   
2025 Earnings Attributable to AEP Common Shareholders $ 223.9  $ 388.5 

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Retail Revenues increased $38 million primarily due to the following:
•A $43 million increase in base case and rider revenues.
•A $24 million increase in weather-normalized revenues primarily in the commercial and industrial classes in Ohio.
These increases were partially offset by:
•An $11 million decrease due to lower prices and lower customer participation in OPCo’s SSO.
•A $9 million decrease in weather-related usage driven by a 20% decrease in cooling degree days in the Eastern Region and a 17% decrease in cooling degree days in the Western Region.
•A $7 million decrease in weather-normalized revenues primarily in the residential class in Texas.
•Off-system Sales increased $13 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.
•Transmission Revenues decreased $6 million primarily due to the following:
•A $35 million decrease due to lower peak loads included in the 2025 billing rates in Texas.
This decrease was partially offset by:
•A $25 million increase in interim rates driven by increased transmission investments in Texas.
24

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

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

•Purchased Electricity from AEP Affiliates expenses decreased $11 million primarily due to decreased recoverable purchases to serve SSO customers in Ohio.
•Other Operation and Maintenance expenses increased $20 million primarily due to the following:
•A $29 million increase in recoverable transmission expenses in Texas.
•A $16 million increase for transmission and distribution related expenses in Texas.
•An $8 million increase in transmission expenses in Ohio primarily due to an increase in recoverable PJM expenses.
•An $8 million increase in distribution expenses in Ohio primarily related to recoverable storm restoration costs and recoverable vegetation management expenses.
These increases were partially offset by:
•A $33 million decrease in employee-related expenses due to the voluntary severance program that occurred in the second quarter of 2024.
•A $9 million decrease related to recoverable energy assistance program expenses for qualified Ohio customers.
•Asset Impairments and Other Related Charges decreased $53 million primarily due to the Federal EPA revised CCR rules finalized in 2024.
•Depreciation and Amortization expenses decreased $25 million primarily due to the following:
•A $16 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.
•An $11 million decrease due to the deferral of eligible costs related to HB 5247.
•A $7 million decrease due to capital rider under-recoveries in Ohio.
These decreases were partially offset by:
•A $9 million increase due to a higher depreciable base in Texas.
•Taxes Other Than Income Taxes decreased $19 million primarily due to the following:
•A $12 million decrease due to lower property taxes in Ohio.
•A $6 million decrease in state excise taxes in Ohio due to decreased billed KWhs in 2025.
•Interest Expense increased $4 million primarily due to the following:
•An $8 million increase due to higher debt balances and interest rates in Texas.
•A $5 million increase due to a decrease of capitalization of AFUDC on prepaid pension and OPEB in Texas.
These increases were partially offset by:
•A $12 million decrease due to the deferral of eligible costs related to HB 5247.
•Income Tax Expense increased $16 million primarily due to the following:
•A $19 million increase due to an increase in pretax book income.
This increase was partially offset by:
•A $5 million decrease due to an increase in amortization of Excess ADIT.

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

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

•Retail Revenues increased $64 million primarily due to the following:
•A $133 million increase in base case and rider revenues.
•A $34 million increase in weather-related usage driven by a 32% increase in heating degree days in the Eastern Region and an 83% increase in heating degree days in the Western Region.
These increases were partially offset by:
•An $88 million decrease due to lower prices and lower customer participation in OPCo’s SSO.
•An $10 million decrease in weather-normalized revenues primarily in the residential class in Texas and Ohio partially offset by an increase in the commercial class in Ohio.
•Off-system Sales increased $26 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.
•Transmission Revenues increased $14 million primarily due to the following:
•A $42 million increase in interim rates driven by increased transmission investments in Texas.
•A $6 million increase in Ohio primarily due to continued transmission investment.
These increases were partially offset by:
•A $34 million decrease due to lower peak loads included in the 2025 billing rates in Texas.

25

•Other Revenues decreased $54 million primarily due to the following:
•A $42 million decrease in Texas primarily due to the maturity of Transition Funding III LLC securitization bonds in December 2024.
•A $7 million decrease in recoverable sales of renewable energy credits in Ohio.
•A $5 million decrease due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

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

•Purchased Electricity for Resale expenses decreased $8 million primarily due to the following:
•A $41 million decrease in recoverable auction purchases primarily due to lower prices in Ohio.
•A $12 million decrease in recoverable alternative energy rider expenses in Ohio.
These decreases were partially offset by:
•A $30 million estimated reduction in regulatory assets for OVEC-related purchased power costs that are no longer probable of future recovery due to recently approved legislation in Ohio.
•A $17 million increase in recoverable OVEC costs.
•Purchased Electricity from AEP Affiliates expenses decreased $41 million primarily due to decreased recoverable purchases to serve SSO customers in Ohio.
•Other Operation and Maintenance expenses increased $78 million primarily due to the following:
•A $58 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
•A $42 million increase in recoverable transmission expenses in Texas.
•An $18 million increase in transmission and distribution related expenses in Texas.
•A $7 million increase in property and liability insurance expenses in Texas.
These increases were partially offset by:
•A $32 million decrease in employee-related expenses due to the voluntary severance program that occurred in the second quarter of 2024.
•A $19 million decrease related to recoverable energy assistance program expenses for qualified Ohio customers.
•Asset Impairments and Other Related Charges decreased $53 million due to the Federal EPA's Revised CCR rules finalized in 2024.
•Depreciation and Amortization expenses decrease $45 million due to the following:
•A $32 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.
•A $19 million decrease primarily due to capital rider under-recoveries in Ohio.
•An $11 million decrease due to the deferral of eligible costs related to HB 5247.
These decreases were partially offset by:
•A $19 million increase due to a higher depreciable base in Texas.
•Interest Expense increased $20 million primarily due to:
•A $26 million increase due to higher debt balances in Ohio and higher debt balances and interest rates in Texas.
•A $5 million increase due to a decrease of capitalization of AFUDC on prepaid pension and OPEB in Texas.
These increases were partially offset by:
•A $12 million decrease due to the deferral of eligible costs related to HB 5247.
•Income Tax Expense increased $18 million due to:
•A $23 million increase due to an increase in pretax book income.
This increase was partially offset by:
•A $7 million decrease due to an increase in amortization of Excess ADIT.

26

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

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

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Transmission Revenues increased $267 million primarily due to the following:
•A $214 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $50 million increase due to continued transmission investment.
27

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

•Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base.
•Interest Expense increased $5 million primarily due to higher long-term debt balances and interest rates.
•Income Tax Expense decreased $196 million primarily due to the following:
•A $254 million decrease due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
This decrease was partially offset by:
•A $51 million increase due to an increase in pretax book income.
•A $7 million increase due to an increase in state taxes.
•Net Income Attributable to Noncontrolling Interests increased $61 million primarily due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.

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

The major components of the increase in Transmission Revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:
 
•Transmission Revenues increased $312 million primarily due to the following:
•A $214 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $97 million increase due to continued transmission investment.

Expenses and Other, Income Tax Expense and Net Income Attributable to Noncontrolling Interests changed between years as follows:
•Depreciation and Amortization expenses increased $20 million due to a higher depreciable base.
•Interest Expense increased $5 million primarily due to higher long-term debt balances and interest rates.
•Income Tax Expense decreased $184 million primarily due to the following:
•A $254 million decrease due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
This decrease was partially offset by:
•A $59 million increase due to an increase in pretax book income.
•An $8 million increase due to an increase in state taxes.
•Net Income Attributable to Noncontrolling Interests increased $60 million primarily due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.
28

GENERATION & MARKETING

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

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Merchant Generation increased $16 million primarily due to higher realized prices in 2025.
•Renewable Generation decreased $9 million primarily due to the sale of Onsite Partners in September 2024.
•Retail, Trading and Marketing increased $92 million primarily due to higher MTM hedging activity and higher market prices in 2025.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $129 million primarily due to an increase in energy costs in 2025.
•Other Operation and Maintenance expenses decreased $43 million primarily due to renewable contract termination proceeds in 2025 and the sale of Onsite Partners in September 2024.
•Asset Impairments and Other Related Charges decreased $76 million due to the Federal EPA’s revised CCR rules finalized in 2024.
•Income Tax Expense increased $25 million primarily due to the following:
•A $19 million increase due to an increase in pretax book income.
•A $2 million increase due to a decrease in the amortization of deferred ITCs.
29

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

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

•Merchant Generation increased $39 million primarily due to higher realized prices in 2025.
•Renewable Generation decreased $16 million primarily due to the sale of Onsite Partners in September 2024.
•Retail, Trading and Marketing increased $258 million primarily due to higher MTM hedging activity and higher market prices in 2025.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $339 million primarily due to an increase in energy costs in 2025.
•Other Operation and Maintenance expenses decreased $44 million primarily due to renewable contract termination proceeds in 2025 and the sale of Onsite Partners in September 2024.
•Asset Impairments and Other Related Charges decreased $76 million due to the Federal EPA’s revised CCR rules finalized in 2024.
•Depreciation and Amortization expenses decreased $5 million primarily due to the sale of Onsite Partners in September 2024.
•Interest and Investment Income decreased $6 million primarily due to the sale of Onsite Partners in September 2024.
•Interest Expense decreased $7 million due to lower advances from affiliates.
•Income Tax Expense increased $36 million primarily due to:
•A $16 million increase due to a decrease in amortization of deferred ITCs primarily from the sale of NMRD in 2024.
•A $14 million increase due to an increase in pretax book income.

30

CORPORATE AND OTHER

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•A $10 million decrease due to the cessation of AEP T&D Services substation construction contracts.
•A $6 million decrease at EIS primarily due to increased insurance reserves.
•A $5 million decrease in interest income primarily due to lower advances to affiliates.
These decreases in earnings were partially offset by:
•A $19 million increase in Income Tax Benefit primarily due to the following:
•A $9 million increase due to a decrease in state taxes.
•A $5 million increase due to a decrease in pretax book income.
•A $4 million increase due to an increase in deferred ITC amortization and PTCs.

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

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

•A $28 million increase in Income Tax Benefit primarily due to the following:
•A $17 million increase due to an increase in deferred ITC amortization and PTCs.
•An $11 million increase due to a decrease in state taxes.
•A $13 million decrease in interest expense due to lower interest rates.
•A $12 million increase in equity earnings.
•An $11 million increase due to the recognition of deferred revenues for completed agreements.
These increases in earnings were partially offset by:
•A $23 million decrease at EIS primarily due to increased insurance reserves.
•A $16 million decrease in interest income primarily due to lower advances to affiliates.

AEP CONSOLIDATED INCOME TAXES

Second Quarter of 2025 Compared to Second Quarter of 2024

Income Tax Benefit increased $258 million primarily due to:
•A $368 million increase due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $32 million increase due to an increase in deferred ITC amortization and PTCs.
These increases in Income Tax Benefit were partially offset by:
•A $145 million decrease due to an increase in pretax book income.

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

Income Tax Benefit decreased $10 million primarily due to:
•A $212 million reduction in Excess ADIT regulatory liabilities at I&M, PSO and SWEPCo as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking recorded in 2024.
•A $158 million decrease due to an increase in pretax book income.
•A $32 million reduction in Excess ADIT regulatory liabilities as a result of the APSC’s denial of SWEPCo’s request to allow the merchant portion of the Turk Plant to serve Arkansas customers recorded in 2024.
•A $15 million decrease due to a decrease in amortization of Excess ADIT.
These decreases in Income Tax Benefit were partially offset by:
•A $368 million increase due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $33 million increase due to an increase in deferred ITC amortization and PTCs.

31

FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization
  June 30, 2025 December 31, 2024
  (dollars in millions)
Long-term Debt, including amounts due within one year $ 44,525.5  57.8  % $ 42,642.8  59.1  %
Short-term Debt 1,501.6  2.0  2,523.8  3.5 
Total Debt 46,027.1  59.8  45,166.6  62.6 
AEP Common Equity 29,871.1  38.8  26,943.8  37.3 
Noncontrolling Interests 1,097.3  1.4  42.3  0.1 
Total Debt and Equity Capitalization $ 76,995.5  100.0  % $ 72,152.7  100.0  %

AEP’s ratio of debt-to-total capital decreased from 62.6% to 59.8% as of December 31, 2024 and June 30, 2025, respectively, primarily due to an increase in earnings and the Midwest Transmission Holdings Noncontrolling Interest transaction, partially offset by an increase in long-term debt to support our capital investment plan in addition to working capital needs.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity for the next twelve months and foreseeable future.  As of June 30, 2025, AEP had $6 billion of revolving credit facilities to support its commercial paper program.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, long-term asset securitizations, leasing agreements, hybrid securities or common stock, including the settlement of the March 2025 forward sale of equity, which is expected to occur on or prior to December 31, 2026. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that there is an increase in interest rates, it could reduce future net income and cash flows and impact financial condition.

Market volatility and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness. AEP continues monitoring the current bank environment and any impacts thereof. AEP was not materially impacted by these conditions during the six months ended June 30, 2025.

Net Available Liquidity

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

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

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries.  The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers.  The maximum amount of commercial paper outstanding during the first six months of 2025 was $2.9 billion.  The weighted-average interest rate for AEP’s commercial paper for the six months ended June 30, 2025 was 4.64%.
32

Other Credit Facilities

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

Securitized Accounts Receivables

AEP Credit’s receivables securitization agreement provides a commitment of $900 million from bank conduits to purchase receivables and expires in September 2026. As of June 30, 2025, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements.  Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of June 30, 2025, this contractually-defined percentage was 56.6%. Non-performance under these covenants could result in an event of default under these credit agreements.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $100 million, would cause an event of default under these credit agreements.  This condition also applies, at the more restrictive level of $50 million of debt outstanding, in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable.  However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

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

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

March 2025 Forward Sale of Equity

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

ATM Program

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

Dividend Policy and Restrictions

The Board of Directors of AEP (AEP Board) declared a quarterly dividend of $0.93 per share in July 2025. Future dividends are at the discretion of the AEP Board and may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 13 for additional information.

Credit Ratings

AEP and its utility subsidiaries do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but its access to the commercial paper market may depend on its credit ratings.  In addition, downgrades in AEP’s credit ratings by one of the rating agencies could increase its borrowing costs.  Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject AEP to additional collateral demands under adequate assurance clauses under its derivative and non-derivative energy contracts.
33

CASH FLOW

AEP relies primarily on cash flows from operations, debt issuances, issuances of common stock and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper and bank term loans, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.
Six Months Ended 
June 30,
  2025 2024
  (in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period $ 246.0  $ 379.0 
Net Cash Flows from Operating Activities 2,671.1  2,904.2 
Net Cash Flows Used for Investing Activities (5,347.3) (3,249.7)
Net Cash Flows from Financing Activities 2,708.8  214.4 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 32.6  (131.1)
Cash, Cash Equivalents and Restricted Cash at End of Period $ 278.6  $ 247.9 

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

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

Net Cash Flows from Operating Activities decreased by $233 million primarily due to the following:
•A $457 million decrease in cash from Change in Other Noncurrent Assets and Change in Other Noncurrent Liabilities. This decrease is primarily due to changes in regulatory assets and liabilities driven by timing differences in collections from and refunds to customers under rate rider mechanisms.
•A $166 million decrease in cash due to changes in risk management contract collateral positions.
•A $161 million decrease in cash primarily due to the timing of fuel and purchase power related revenues and expenses.
•A $95 million decrease in cash due to a discretionary contribution to the qualified pension plan. See Note 7 - Benefit Plans for additional information.
These decreases in cash were partially offset by:
•A $664 million increase in cash from Net Income, after non-cash adjustments. See “Results of Operations” for further detail.

34

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

Net Cash Flows Used for Investing Activities increased by $2.1 billion primarily due to the following:
•A $1.4 billion increase due to the acquisitions of Green Country Power Plant, Pixley Solar Energy Facility and Flat Ridge IV Wind Energy Facility. See “Acquisitions” section of Note 6 for additional information.
•A $702 million increase in Construction Expenditures primarily due to increases in Vertically Integrated Utilities of $313 million, Transmission and Distribution Utilities of $247 million and AEP Transmission Holdco of $119 million.
•A $114 million decrease in Proceeds from Sale of Equity Method Investment. See “Disposition of NMRD” section of Note 6 for additional information.

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

Net Cash Flows from Financing Activities increased by $2.5 billion primarily due to the following:
•A $2.8 billion increase due to proceeds from the Midwest Transmission Holdings Noncontrolling Interest transaction. See “Noncontrolling Interest in OHTCo and IMTCo” section of Note 6 for additional information.
•A $445 million decrease in retirements of long-term debt. See Note 13 - Financing Activities for additional information.
These increases in cash were partially offset by:
•A $500 million decrease in issuances of long-term debt. See Note 13 - Financing Activities for additional information.
•A $344 million decrease in issuances of common stock primarily under AEP’s ATM Program. See Note 13 - Financing Activities for additional information.

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


35

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $11.5 billion of capital expenditures in 2025.  For the four-year period, 2026 through 2029, management forecasts capital expenditures of $42.9 billion. Management’s forecasted capital expenditures reflect planned increases in investments for transmission infrastructure and new generation resources to support forecasted large load increases and continued improvements in distribution system reliability.

Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews, inflation and the ability to access capital.  Management has funded, or expects to fund, these capital expenditures through cash flows from operations, proceeds from the strategic sale of assets and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. For more information of forecasted capital expenditures, see the “Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2024 Annual Report.

SIGNIFICANT CASH REQUIREMENTS

A summary of significant cash requirements is included in the 2024 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2024 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits, asset retirement obligations and the impact of new accounting standards and SEC rulemaking activity.

ACCOUNTING STANDARDS

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

36

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

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

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

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

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

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

MTM Derivative Contract Net Assets (Liabilities)

Six Months Ended June 30, 2025
Vertically
Integrated
Utilities		 Transmission
and
Distribution
Utilities		 Generation
&
Marketing		 Total
  (in millions)
Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of December 31, 2024
 $ 91.8  $ (48.0) $ 161.8  $ 205.6 
Gain from Contracts Realized/Settled During the Period and
Entered in a Prior Period
 (72.0) (1.1) (17.0) (90.1)
Fair Value of New Contracts at Inception When Entered
During the Period (a)
 —  —  10.7  10.7 
Changes in Fair Value Due to Market Fluctuations During
the Period (b)
 (20.5) —  50.0  29.5 
Changes in Fair Value Allocated to Regulated Jurisdictions (c) 285.1  1.1  —  286.2 
Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of June 30, 2025
 $ 284.4  $ (48.0) $ 205.5  441.9 
Commodity Cash Flow Hedge Contracts
   115.9 
Fair Value Hedge Contracts     (47.9)
Collateral Deposits     (79.4)
Total MTM Derivative Contract Net Assets as of June 30, 2025
     $ 430.5 
37

(a)Reflects fair value on primarily auctions or long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.
(b)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable on the balance sheet.

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

Credit Risk

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

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

As of June 30, 2025, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:
Counterparty Credit Quality Exposure
Before
Credit
Collateral		 Credit
Collateral		 Net
Exposure		 Number of
Counterparties
>10% of
Net Exposure		 Net Exposure
of
Counterparties
>10%
  (in millions, except number of counterparties)
Investment Grade $ 642.8  $ 94.9  $ 547.9  3  $ 351.1 
Non-investment Grade 3.5  —  3.5  2  3.5 
No External Ratings:    
Internal Investment Grade 18.4  —  18.4  3  13.4 
Internal Non-investment Grade 104.4  70.5  33.9  2  27.8 
Total as of June 30, 2025 $ 769.1  $ 165.4  $ 603.7 

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

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

Value at Risk (VaR) Associated with Risk Management Contracts

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

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


38

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

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

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

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

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

Interest Rate Risk

AEP is exposed to interest rate market fluctuations in the normal course of business operations. Prior to 2022, interest rates remained at low levels and the Federal Reserve maintained the federal funds target range at 0.0% to 0.25% for much of 2021. During 2022 and 2023, the Federal Reserve approved 11 rate increases for a total cumulative increase of 5.25%. In light of the progress on inflation and the balance of risks, during 2024, the Federal Reserve authorized three rate decreases for a total cumulative decrease of 1.0%. AEP has outstanding short and long-term debt which is subject to variable rates. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes on interest rates. For the six months ended June 30, 2025 and 2024, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $34 million and $25 million, respectively.
39


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions, except per-share and share amounts)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2025 2024 2025 2024
REVENUES
Vertically Integrated Utilities $ 2,934.5  $ 2,572.0  $ 6,020.0  $ 5,473.2 
Transmission and Distribution Utilities 1,442.6  1,428.8  2,958.1  2,912.0 
Generation & Marketing 551.0  442.5  1,281.6  958.4 
Other Revenues 158.8  135.9  290.6  261.3 
TOTAL REVENUES 5,086.9  4,579.2  10,550.3  9,604.9 
EXPENSES        
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 1,541.4  1,368.5  3,394.3  2,944.3 
Other Operation 537.6  817.3  1,290.0  1,579.6 
Maintenance 390.7  351.5  709.2  669.0 
Asset Impairments and Other Related Charges —  142.5  —  142.5 
Depreciation and Amortization 853.1  821.9  1,686.5  1,609.0 
Taxes Other Than Income Taxes 365.0  393.6  787.0  804.0 
TOTAL EXPENSES 3,687.8  3,895.3  7,867.0  7,748.4 
OPERATING INCOME 1,399.1  683.9  2,683.3  1,856.5 
Other Income (Expense):        
Other Income 15.5  13.1  23.3  26.7 
Allowance for Equity Funds Used During Construction 57.1  55.2  114.4  98.8 
Non-Service Cost Components of Net Periodic Benefit Cost 34.6  37.4  69.7  82.5 
Interest Expense (489.5) (465.6) (984.4) (901.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS 1,016.8  324.0  1,906.3  1,163.3 
Income Tax Expense (Benefit) (250.9) 6.7  (125.4) (135.2)
Equity Earnings of Unconsolidated Subsidiaries 20.6  25.2  58.8  49.7 
NET INCOME 1,288.3  342.5  2,090.5  1,348.2 
Net Income Attributable to Noncontrolling Interests 62.5  2.2  64.5  4.8 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 1,225.8  $ 340.3  $ 2,026.0  $ 1,343.4 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING 534,283,554  528,898,816  533,839,985  527,725,426 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 2.29  $ 0.64  $ 3.80  $ 2.55 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 536,425,635  530,140,990  535,547,029  528,868,693 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 2.29  $ 0.64  $ 3.78  $ 2.54 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
40

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
2025 2024 2025 2024
Net Income $ 1,288.3  $ 342.5  $ 2,090.5  $ 1,348.2 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES        
Cash Flow Hedges, Net of Tax of $(8.8) and $5.9 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $(2.7) and $4.3 for the Six Months Ended June 30, 2025 and 2024, Respectively
 (33.2) 22.4  (10.1) 16.2 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $0.1 and $(0.2) for the Six Months Ended June 30, 2025 and 2024, Respectively
 0.3  (0.1) 0.6  (0.7)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) (32.9) 22.3  (9.5) 15.5 
TOTAL COMPREHENSIVE INCOME 1,255.4  364.8  2,081.0  1,363.7 
Total Comprehensive Income Attributable To Noncontrolling Interests 62.5  2.2  64.5  4.8 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 1,192.9  $ 362.6  $ 2,016.5  $ 1,358.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
41

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
AEP Common Shareholders
Common Stock Accumulated
Other
Comprehensive
Income (Loss)
Shares Amount Paid-in
Capital		 Retained
Earnings		 Noncontrolling
Interests		 Total
TOTAL EQUITY – DECEMBER 31, 2023 527.4  $ 3,427.9  $ 9,073.9  $ 12,800.4  $ (55.5) $ 39.2  $ 25,285.9 
Issuance of Common Stock 0.8  5.4  35.2    40.6 
Common Stock Dividends (465.5) (a) (1.4) (466.9)
Other Changes in Equity (14.8) (14.8)
Net Income       1,003.1  2.6  1,005.7 
Other Comprehensive Loss         (6.8) (6.8)
TOTAL EQUITY – MARCH 31, 2024 528.2  3,433.3  9,094.3  13,338.0  (62.3) 40.4  25,843.7 
Issuance of Common Stock 4.9  32.1  403.1        435.2 
Common Stock Dividends       (467.0) (a)   (2.1) (469.1)
Other Changes in Equity     1.1    1.1 
Net Income       340.3    2.2  342.5 
Other Comprehensive Income         22.3    22.3 
TOTAL EQUITY – JUNE 30, 2024 533.1  $ 3,465.4  $ 9,498.5  $ 13,211.3  $ (40.0) $ 40.5  $ 26,175.7 
TOTAL EQUITY – DECEMBER 31, 2024 534.1  $ 3,471.6  $ 9,606.1  $ 13,869.2  $ (3.1) $ 42.3  $ 26,986.1 
Issuance of Common Stock 1.1  7.1  68.3  75.4 
Common Stock Dividends (500.0) (b) (1.0) (501.0)
Other Changes in Equity (22.1) (22.1)
Net Income 800.2  2.0  802.2 
Other Comprehensive Income 23.4  23.4 
TOTAL EQUITY – MARCH 31, 2025 535.2  3,478.7  9,652.3  14,169.4  20.3  43.3  27,364.0 
Issuance of Common Stock 0.6  3.7  52.7  56.4 
Common Stock Dividends (498.5) (b) (1.0) (499.5)
Other Changes in Equity 9.1  0.1  9.2 
Midwest Transmission Holdings Noncontrolling Interest Transaction 1,790.5  992.4  2,782.9 
Net Income 1,225.8  62.5  1,288.3 
Other Comprehensive Loss (32.9) (32.9)
TOTAL EQUITY – JUNE 30, 2025 535.8  $ 3,482.4  $ 11,504.6  $ 14,896.7  $ (12.6) $ 1,097.3  $ 30,968.4 

(a)    Cash dividends declared per AEP common share were $0.88.
(b)    Cash dividends declared per AEP common share were $0.93.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
42

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
  June 30, December 31,
  2025 2024
CURRENT ASSETS    
Cash and Cash Equivalents $ 227.3  $ 202.9 
Restricted Cash
(June 30, 2025 and December 31, 2024 Amounts Include $51.3 and $43.1, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding, Storm Recovery Funding and Cost Recovery Funding)
 51.3  43.1 
Other Temporary Investments
(June 30, 2025 and December 31, 2024 Amounts Include $197.9 and $206.7, Respectively, Related to EIS)
 212.0  215.4 
Accounts Receivable:    
Customers 1,134.6  1,100.1 
Accrued Unbilled Revenues 393.7  367.0 
Pledged Accounts Receivable – AEP Credit 1,279.0  1,161.5 
Miscellaneous 53.4  64.1 
Allowance for Credit Losses (63.6) (60.8)
Total Accounts Receivable 2,797.1  2,631.9 
Fuel 616.9  748.9 
Materials and Supplies 1,005.1  966.2 
Risk Management Assets 469.3  210.4 
Accrued Tax Benefits 111.6  38.2 
Regulatory Asset for Under-Recovered Fuel Costs 547.4  445.9 
Prepayments and Other Current Assets 283.9  285.9 
TOTAL CURRENT ASSETS 6,321.9  5,788.8 
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 26,039.7  24,829.7 
Transmission 40,304.3  38,871.9 
Distribution 32,125.2  31,061.9 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 8,378.2  7,491.6 
Construction Work in Progress 6,945.3  6,346.9 
Total Property, Plant and Equipment 113,792.7  108,602.0 
Accumulated Depreciation and Amortization 27,455.6  26,186.4 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 86,337.1  82,415.6 
OTHER NONCURRENT ASSETS    
Regulatory Assets 4,870.2  5,129.2 
Securitized Assets 973.1  554.3 
Spent Nuclear Fuel and Decommissioning Trusts 4,609.7  4,395.1 
Goodwill 52.5  52.5 
Long-term Risk Management Assets 258.9  289.1 
Operating Lease Assets 580.6  580.1 
Deferred Charges and Other Noncurrent Assets 3,774.5  3,873.3 
TOTAL OTHER NONCURRENT ASSETS 15,119.5  14,873.6 
TOTAL ASSETS $ 107,778.5  $ 103,078.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
43

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2025 and December 31, 2024
(in millions, except per-share and share amounts)
(Unaudited)
      June 30, December 31,
  2025 2024
CURRENT LIABILITIES    
Accounts Payable $ 2,714.2  $ 2,637.6 
Short-term Debt:    
Securitized Debt for Receivables – AEP Credit 900.0  900.0 
Other Short-term Debt 601.6  1,623.8 
Total Short-term Debt 1,501.6  2,523.8 
Long-term Debt Due Within One Year
(June 30, 2025 and December 31, 2024 Amounts Include $181.9 and $216.5, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)
 3,212.4  3,335.0 
Risk Management Liabilities 106.1  100.0 
Customer Deposits 454.3  454.7 
Accrued Taxes 1,527.8  1,922.1 
Accrued Interest 479.2  453.3 
Obligations Under Operating Leases 91.0  91.9 
Other Current Liabilities 1,356.7  1,490.9 
TOTAL CURRENT LIABILITIES 11,443.3  13,009.3 
NONCURRENT LIABILITIES    
Long-term Debt
(June 30, 2025 and December 31, 2024 Amounts Include $1,354.4 and $826.5, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)
 41,313.1  39,307.8 
Long-term Risk Management Liabilities 191.6  224.4 
Deferred Income Taxes 10,521.7  9,972.4 
Regulatory Liabilities and Deferred Investment Tax Credits 7,973.9  8,344.0 
Asset Retirement Obligations 3,625.1  3,530.6 
Employee Benefits and Pension Obligations 270.5  360.7 
Obligations Under Operating Leases 506.5  504.3 
Deferred Credits and Other Noncurrent Liabilities 913.8  800.6 
TOTAL NONCURRENT LIABILITIES 65,316.2  63,044.8 
TOTAL LIABILITIES 76,759.5  76,054.1 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
MEZZANINE EQUITY
Contingently Redeemable Performance Share Awards 50.6  37.8 
TOTAL MEZZANINE EQUITY 50.6  37.8 
EQUITY    
Common Stock – Par Value – $6.50 Per Share:
    
2025 2024    
Shares Authorized 600,000,000 600,000,000    
Shares Issued 535,755,643 534,094,530    
(1,186,815 Shares were Held in Treasury as of June 30, 2025 and December 31, 2024, Respectively)
 3,482.4  3,471.6 
Paid-in Capital 11,504.6  9,606.1 
Retained Earnings 14,896.7  13,869.2 
Accumulated Other Comprehensive Income (Loss) (12.6) (3.1)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY 29,871.1  26,943.8 
Noncontrolling Interests 1,097.3  42.3 
TOTAL EQUITY 30,968.4  26,986.1 
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY $ 107,778.5  $ 103,078.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
44

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Six Months Ended June 30,
  2025 2024
OPERATING ACTIVITIES    
Net Income $ 2,090.5  $ 1,348.2 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 1,686.5  1,609.0 
Deferred Income Taxes (53.6) (56.1)
Asset Impairments and Other Related Charges —  142.5 
Allowance for Equity Funds Used During Construction (114.4) (98.8)
Mark-to-Market of Risk Management Contracts (240.6) (75.0)
Pension Contributions to Qualified Plan Trust (94.7) — 
Property Taxes 240.6  213.2 
Deferred Fuel Over/Under-Recovery, Net (41.3) 120.0 
Change in Other Noncurrent Assets (439.5) (131.0)
Change in Other Noncurrent Liabilities 41.4  189.9 
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net (176.4) (209.3)
Fuel, Materials and Supplies 114.3  111.3 
Accounts Payable 286.9  77.0 
Accrued Taxes, Net (468.5) (301.3)
Other Current Assets 10.6  (144.0)
Other Current Liabilities (170.7) 108.6 
Net Cash Flows from Operating Activities 2,671.1  2,904.2 
INVESTING ACTIVITIES    
Construction Expenditures (4,020.2) (3,318.3)
Purchases of Investment Securities (1,336.5) (1,190.1)
Sales of Investment Securities 1,311.0  1,157.1 
Acquisitions of Generation Facilities (1,359.3) — 
Acquisitions of Nuclear Fuel (45.6) (69.8)
Proceeds from Sale of Equity Method Investment —  114.0 
Other Investing Activities 103.3  57.4 
Net Cash Flows Used for Investing Activities (5,347.3) (3,249.7)
FINANCING ACTIVITIES    
Issuance of Common Stock 131.8  475.8 
Issuance of Long-term Debt 3,163.2  3,663.3 
Issuance of Short-term Debt with Original Maturities greater than 90 Days 319.9  376.6 
Change in Short-term Debt with Original Maturities less than 90 Days, Net (764.3) (860.0)
Retirement of Long-term Debt (1,324.1) (1,769.1)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days (577.8) (665.1)
Principal Payments for Finance Lease Obligations (25.0) (35.8)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs 2,782.9  — 
Dividends Paid on Common Stock (1,000.5) (936.0)
Other Financing Activities 2.7  (35.3)
Net Cash Flows from Financing Activities 2,708.8  214.4 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 32.6  (131.1)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 246.0  379.0 
Cash, Cash Equivalents and Restricted Cash at End of Period $ 278.6  $ 247.9 
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 946.2  $ 881.0 
Net Cash Paid for Income Taxes 59.3  60.8 
Cash Paid (Received) for Transferable Tax Credits (17.2) (72.2)
Noncash Acquisitions Under Finance Leases 16.7  20.5 
Construction Expenditures Included in Current Liabilities as of June 30, 1,059.1  1,049.9 
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 33.4  8.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
45

AEP TEXAS INC. AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
  Three Months Ended 
June 30,		 Six Months Ended 
June 30,
  2025 2024 2025 2024
  (in millions of KWhs)
Retail:    
Residential 3,275  3,529  6,191  6,058 
Commercial 4,719  4,143  8,818  7,450 
Industrial 3,300  3,324  6,670  6,597 
Miscellaneous 147  156  291  307 
Total Retail 11,441  11,152  21,970  20,412 


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










46

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

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Retail Revenues increased $24 million primarily due to the following:
•A $35 million increase in base case and rider revenues.
This increase was partially offset by:
•A $7 million decrease in weather-normalized revenues primarily in the residential class.
•A $4 million decrease in weather-related usage primarily due to a 17% decrease in cooling degree days.
•Transmission Revenues decreased $9 million primarily due to the following:
•A $35 million decrease due to lower peak loads included in the 2025 billing rates.
This decrease was partially offset by:
•A $25 million increase in interim rates driven by increased transmission investments.
•Other Revenues decreased $23 million primarily due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

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

•Other Operation and Maintenance expenses increased $25 million primarily due to the following:
•A $29 million increase in recoverable transmission expenses.
•A $16 million increase in transmission and distribution-related expenses.
These increases were partially offset by:
•A $20 million decrease in employee-related expenses due to the voluntary severance program that occurred in the second quarter of 2024.
47

•Depreciation and Amortization expenses decreased $18 million primarily due to:
•A $16 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.
•An $11 million decrease due to the deferral of eligible costs related to HB 5247.
These decreases were partially offset by:
•A $9 million increase due to a higher depreciable base.
•Interest Expense increased $1 million primarily due to the following:
•An $8 million increase due to higher debt balances and interest rates.
•A $5 million increase due to a decrease in capitalization of AFUDC on prepaid pension and OPEB.
These increases were partially offset by:
•A $12 million decrease due to the deferral of eligible costs related to HB 5247.
•Income Tax Expense decreased $10 million primarily due to an increase in amortization of Excess ADIT.

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

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

•Retail Revenues increased $82 million primarily due to the following:
•A $76 million increase in base case and rider revenues.
•A $12 million increase in weather-related usage primarily due to an 83% increase in heating degree days.
These increases were partially offset by:
•A $6 million decrease in weather-normalized revenues primarily in the residential class.
•Transmission Revenues increased $8 million due to the following:
•A $42 million increase in interim rates driven by increased transmission investments.
This increase was partially offset by:
•A $34 million decrease due to lower peak loads included in the 2025 billing rates.
•Other Revenues decreased $42 million primarily due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

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

•Other Operation and Maintenance expenses increased $52 million primarily due to the following:
•A $42 million increase in recoverable transmission expenses.
•An $18 million increase in transmission and distribution-related expenses.
•A $7 million increase in property and liability insurance expenses.
These increases were partially offset by:
•A $20 million decrease in employee-related expenses due to the voluntary severance program that occurred in the second quarter of 2024.
•Depreciation and Amortization expenses decreased $26 million primarily due to the following:
•A $32 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.
•An $11 million decrease due to the deferral of eligible costs related to HB 5247.
These decreases were partially offset by:
•A $19 million increase due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $5 million primarily due to higher property taxes driven by increased investment.
•Interest Expense increased $13 million primarily due to the following:
•A $19 million increase due to higher debt balances and interest rates.
•A $5 million increase due to a decrease in capitalization of AFUDC on prepaid pension and OPEB.
These increases were partially offset by:
•A $12 million decrease due to the deferral of eligible costs related to HB 5247.
•Income Tax Expense decreased $9 million primarily due to an increase in amortization of Excess ADIT.
48


AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
    2025   2024 2025 2024
REVENUES        
Electric Transmission and Distribution   $ 528.3  $ 537.7  $ 1,048.3  $ 1,000.7 
Sales to AEP Affiliates   1.4  1.4  2.7  2.7 
Other Revenues   1.5  0.5  3.2  2.6 
TOTAL REVENUES   531.2  539.6  1,054.2  1,006.0 
 
EXPENSES          
Other Operation   163.8  147.8  330.0  288.6 
Maintenance   30.2  21.7  54.5  43.8 
Depreciation and Amortization   106.8  124.9  215.7  241.6 
Taxes Other Than Income Taxes   39.0  40.6  85.5  80.6 
TOTAL EXPENSES   339.8  335.0  685.7  654.6 
 
OPERATING INCOME   191.4  204.6  368.5  351.4 
 
Other Income (Expense):          
Interest Income   0.4  2.1  0.6  2.6 
Allowance for Equity Funds Used During Construction 12.5  15.5  24.0  24.1 
Non-Service Cost Components of Net Periodic Benefit Cost 5.3  3.4  11.1  7.1 
Interest Expense   (60.7) (59.3) (133.8) (120.8)
 
INCOME BEFORE INCOME TAX EXPENSE   148.9  166.3  270.4  264.4 
 
Income Tax Expense   27.8  37.9  47.7  56.3 
NET INCOME   $ 121.1  $ 128.4  $ 222.7  $ 208.1 
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
49

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

50

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

51

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
    June 30, December 31,
    2025   2024
CURRENT ASSETS        
Cash and Cash Equivalents $ 0.1  $ 0.1 
Restricted Cash
(June 30, 2025 and December 31, 2024 Amounts Include $13.3 and $23.5, Respectively, Related to Transition Funding and Restoration Funding)
 13.3  23.5 
Advances to Affiliates 7.1  7.2 
Accounts Receivable:      
Customers   200.8  182.8 
Affiliated Companies   12.4  10.7 
Accrued Unbilled Revenues 108.2  97.2 
Miscellaneous   0.1  0.3 
Allowance for Credit Losses (4.1) (4.3)
Total Accounts Receivable   317.4  286.7 
Materials and Supplies   148.6  169.5 
Prepayments and Other Current Assets   6.5  13.4 
TOTAL CURRENT ASSETS   493.0  500.4 
 
PROPERTY, PLANT AND EQUIPMENT      
Electric:      
Transmission
   7,942.7  7,546.2 
Distribution
   6,501.1  6,250.5 
Other Property, Plant and Equipment   1,198.4  1,175.7 
Construction Work in Progress   1,183.6  1,118.0 
Total Property, Plant and Equipment   16,825.8  16,090.4 
Accumulated Depreciation and Amortization   2,144.3  2,046.9 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET   14,681.5  14,043.5 
 
OTHER NONCURRENT ASSETS      
Regulatory Assets   383.3  353.6 
Securitized Assets
(June 30, 2025 and December 31, 2024 Amounts Include $105.1 and $116.7, Respectively, Related to Restoration Funding)
 105.1  116.7 
Operating Lease Assets 51.0  54.4 
Deferred Charges and Other Noncurrent Assets   194.5  131.0 
TOTAL OTHER NONCURRENT ASSETS   733.9  655.7 
 
TOTAL ASSETS   $ 15,908.4  $ 15,199.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
52

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
June 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
    June 30, December 31,
    2025   2024
CURRENT LIABILITIES  
Advances from Affiliates   $ 109.5  $ 284.9 
Accounts Payable:  
General   318.2  366.2 
Affiliated Companies   28.7  34.9 
Long-term Debt Due Within One Year – Nonaffiliated
(June 30, 2025 and December 31, 2024 Amounts Include $24.7 and $24.4, Respectively, Related to Restoration Funding)
 774.7  324.5 
Accrued Taxes   141.7  127.1 
Accrued Interest
(June 30, 2025 and December 31, 2024 Amounts Include $0.9 and $1.9, Respectively, Related to Restoration Funding)
 57.4  55.0 
Obligations Under Operating Leases 12.8  13.1 
Other Current Liabilities   183.0  201.4 
TOTAL CURRENT LIABILITIES   1,626.0  1,407.1 
 
NONCURRENT LIABILITIES      
Long-term Debt – Nonaffiliated
(June 30, 2025 and December 31, 2024 Amounts Include $90.1 and $102.4, Respectively, Related to Restoration Funding)
 6,057.6  6,117.1 
Deferred Income Taxes   1,378.2  1,322.7 
Regulatory Liabilities and Deferred Investment Tax Credits   1,285.6  1,285.4 
Obligations Under Operating Leases 40.6  43.4 
Deferred Credits and Other Noncurrent Liabilities   163.0  139.3 
TOTAL NONCURRENT LIABILITIES   8,925.0  8,907.9 
 
TOTAL LIABILITIES   10,551.0  10,315.0 
 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)  
 
COMMON SHAREHOLDER’S EQUITY      
Paid-in Capital   2,342.9  2,092.4 
Retained Earnings   3,017.9  2,795.2 
Accumulated Other Comprehensive Income (Loss) (3.4) (3.0)
TOTAL COMMON SHAREHOLDER’S EQUITY   5,357.4  4,884.6 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY   $ 15,908.4  $ 15,199.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
53

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
    Six Months Ended June 30,
    2025   2024
OPERATING ACTIVITIES        
Net Income   $ 222.7  $ 208.1 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:      
Depreciation and Amortization   215.7  241.6 
Deferred Income Taxes   36.4  45.1 
Allowance for Equity Funds Used During Construction (24.0) (24.1)
Pension Contributions to Qualified Plan Trust (12.0) — 
Property Taxes (57.9) (53.5)
Change in Other Noncurrent Assets   (49.9) (57.0)
Change in Other Noncurrent Liabilities   35.1  19.7 
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net   (30.7) (73.1)
Materials and Supplies   20.9  5.0 
Accounts Payable   2.6  26.0 
Accrued Taxes, Net 14.6  43.6 
Other Current Assets   8.1  — 
Other Current Liabilities   (22.8) 4.7 
Net Cash Flows from Operating Activities   358.8  386.1 
 
INVESTING ACTIVITIES      
Construction Expenditures   (863.4) (665.3)
Change in Advances to Affiliates, Net 0.1  (251.1)
Other Investing Activities 32.3  32.8 
Net Cash Flows Used for Investing Activities   (831.0) (883.6)
 
FINANCING ACTIVITIES      
Capital Contribution from Parent 250.5  1.6 
Issuance of Long-term Debt – Nonaffiliated 399.8  841.9 
Change in Advances from Affiliates, Net   (175.4) (103.7)
Retirement of Long-term Debt – Nonaffiliated   (12.2) (244.5)
Principal Payments for Finance Lease Obligations   (3.7) (3.7)
Other Financing Activities 3.0  1.3 
Net Cash Flows from Financing Activities   462.0  492.9 
Net Decrease in Cash, Cash Equivalents and Restricted Cash   (10.2) (4.6)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period   23.6  34.1 
Cash, Cash Equivalents and Restricted Cash at End of Period   $ 13.4  $ 29.5 
 
SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts   $ 124.8  $ 111.0 
Net Cash Paid (Received) for Income Taxes   (8.4) (5.4)
Noncash Acquisitions Under Finance Leases   3.9  2.1 
Construction Expenditures Included in Current Liabilities as of June 30,   207.1  191.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
54

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Summary of Investment in Transmission Assets for AEPTCo
As of June 30,
2025 2024
(in millions)
Plant In Service $ 16,089.7  $ 14,608.3 
Construction Work in Progress 2,105.1  1,914.5 
Accumulated Depreciation and Amortization 1,759.6  1,436.8 
Total Transmission Property, Net $ 16,435.2  $ 15,086.0 

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

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Transmission Revenues increased $267 million primarily due to the following:
•A $214 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $49 million increase due to continued transmission investment.


55

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

•Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base.
•Interest Expense increased $5 million primarily due to higher long-term debt balances and interest rates.
•Income Tax Expense decreased $193 million primarily due to the following:
•A $254 million decrease due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
This decrease was partially offset by:
•A $52 million increase due to an increase in pretax book income.
•Net Income Attributable to Noncontrolling Interest increased $61 million due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.

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

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

•Transmission Revenues increased $311 million primarily due to the following:
•A $214 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $96 million increase due to continued transmission investment.

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

•Depreciation and Amortization expenses increased $20 million due to a higher depreciable base.
•Interest Expense increased $5 million primarily due to higher long-term debt balances and interest rates.
•Income Tax Expense decreased $184 million primarily due to the following:
•A $254 million decrease due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
This decrease was partially offset by:
•A $60 million increase due to an increase in pretax book income.
•Net Income Attributable to Noncontrolling Interest increased $61 million due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.


56


AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2025   2024   2025   2024
REVENUES
Transmission Revenues $ 110.7  $ 97.3  $ 216.7  $ 195.7 
Sales to AEP Affiliates 469.9  394.4  900.1  783.8 
(Provision for)/Reversal of – Revenue Refund – Affiliated 127.2  (16.6) 119.8  (22.6)
(Provision for)/ Reversal of – Revenue Refund – Nonaffiliated 33.9  (0.3) 32.2  (1.7)
Other Revenues 0.1  0.4  0.1  2.8 
TOTAL REVENUES 741.8  475.2  1,268.9  958.0 
EXPENSES        
Other Operation 35.8  40.0  64.8  69.9 
Maintenance 6.4  5.0  11.8  10.3 
Depreciation and Amortization 118.9  106.7  233.0  212.6 
Taxes Other Than Income Taxes 75.8  75.5  149.9  148.9 
TOTAL EXPENSES 236.9  227.2  459.5  441.7 
OPERATING INCOME 504.9  248.0  809.4  516.3 
Other Income (Expense):        
Interest Income – Affiliated 1.4  4.3  1.8  6.2 
Allowance for Equity Funds Used During Construction 21.5  22.5  43.9  40.4 
Interest Expense (56.6) (51.4) (111.6) (106.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 471.2  223.4  743.5  456.7 
Income Tax Expense (Benefit) (145.3) 47.7  (84.5) 99.8 
NET INCOME 616.5  175.7  828.0  356.9 
Net Income Attributable to Noncontrolling Interest 60.7  —  60.7  — 
EARNINGS ATTRIBUTABLE TO AEPTCo COMMON SHAREHOLDER $ 555.8  $ 175.7  $ 767.3  $ 356.9 
AEPTCo is wholly-owned by AEP Transmission Holdco.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
57

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
    Paid-in
Capital		 Retained
Earnings		 Noncontrolling
Interest		 Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2023   $ 3,043.4  $ 3,289.9  $ —  $ 6,333.3 
   
Capital Contribution from AEP Member 25.0  25.0 
Dividends Paid to AEP Member (40.0) (40.0)
Net Income   181.2  181.2 
TOTAL MEMBER'S EQUITY – MARCH 31, 2024 3,068.4  3,431.1  —  6,499.5 
Capital Contribution from AEP Member 9.6  9.6 
Dividends Paid to AEP Member (31.0) (31.0)
Net Income 175.7  175.7 
TOTAL MEMBER'S EQUITY – JUNE 30, 2024 $ 3,078.0  $ 3,575.8  $ —  $ 6,653.8 
   
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2024   $ 3,100.6  $ 3,850.3  $ —  $ 6,950.9 
Capital Contribution from AEP Member 32.5  32.5 
Dividends Paid to AEP Member (42.5) (42.5)
Net Income 211.5  211.5 
TOTAL MEMBER'S EQUITY – MARCH 31, 2025 3,133.1  4,019.3  —  7,152.4 
   
Capital Contribution from AEP Member 8.3  8.3 
Dividends Paid to AEP Member (2,835.8) (2,835.8)
Midwest Transmission Holdings Noncontrolling Interest Transaction 1,790.5  992.4  2,782.9 
Net Income 555.8  60.7  616.5 
TOTAL MEMBER'S EQUITY – JUNE 30, 2025 $ 4,931.9  $ 1,739.3  $ 1,053.1  $ 7,724.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
58

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
    June 30,   December 31,
    2025   2024
CURRENT ASSETS        
Advances to Affiliates   $ 67.9  $ 30.4 
Accounts Receivable:  
Customers   68.7  58.9 
Affiliated Companies   170.7  134.1 
Miscellaneous —  1.3 
Total Accounts Receivable   239.4  194.3 
Prepayments and Other Current Assets   14.9  11.1 
TOTAL CURRENT ASSETS   322.2  235.8 
 
TRANSMISSION PROPERTY      
Transmission Property   15,544.3  14,913.4 
Other Property, Plant and Equipment   545.4  516.1 
Construction Work in Progress   2,105.1  1,965.4 
Total Transmission Property   18,194.8  17,394.9 
Accumulated Depreciation and Amortization   1,759.6  1,578.4 
TOTAL TRANSMISSION PROPERTY – NET   16,435.2  15,816.5 
 
OTHER NONCURRENT ASSETS      
Regulatory Assets   56.3  0.4 
Deferred Property Taxes   177.5  308.9 
Deferred Charges and Other Noncurrent Assets   41.6  8.7 
TOTAL OTHER NONCURRENT ASSETS   275.4  318.0 
 
TOTAL ASSETS   $ 17,032.8  $ 16,370.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
59

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
June 30, 2025 and December 31, 2024
(Unaudited)
    June 30,   December 31,
    2025   2024
(in millions)
CURRENT LIABILITIES        
Advances from Affiliates   $ 47.7  $ 84.7 
Accounts Payable:    
General   335.9  360.5 
Affiliated Companies   107.3  117.0 
Long-term Debt Due Within One Year – Nonaffiliated —  90.0 
Accrued Taxes   476.2  665.9 
Accrued Interest   47.3  44.9 
Obligations Under Operating Leases 1.2  1.3 
Other Current Liabilities   44.4  44.5 
TOTAL CURRENT LIABILITIES   1,060.0  1,408.8 
 
NONCURRENT LIABILITIES      
Long-term Debt – Nonaffiliated   6,098.5  5,678.1 
Deferred Income Taxes   1,484.6  1,278.6 
Regulatory Liabilities   643.2  878.4 
Obligations Under Operating Leases 1.6  1.2 
Deferred Credits and Other Noncurrent Liabilities   20.6  174.3 
TOTAL NONCURRENT LIABILITIES   8,248.5  8,010.6 
 
TOTAL LIABILITIES   9,308.5  9,419.4 
 
Rate Matters (Note 4)  
Commitments and Contingencies (Note 5)  
 
MEMBER’S EQUITY      
Paid-in Capital 4,931.9  3,100.6 
Retained Earnings   1,739.3  3,850.3 
TOTAL MEMBER’S EQUITY   6,671.2  6,950.9 
Noncontrolling Interest 1,053.1  — 
TOTAL EQUITY 7,724.3  6,950.9 
 
TOTAL LIABILITIES AND EQUITY   $ 17,032.8  $ 16,370.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
60

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
    Six Months Ended June 30,
    2025 2024
OPERATING ACTIVITIES  
Net Income   $ 828.0  $ 356.9 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization   233.0  212.6 
Deferred Income Taxes   (136.5) 49.4 
Allowance for Equity Funds Used During Construction   (43.9) (40.4)
Property Taxes   131.4  116.2 
Change in Other Noncurrent Assets   (44.9) — 
Change in Other Noncurrent Liabilities   (152.3) (28.9)
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net   (45.1) (23.8)
Materials and Supplies —  (0.2)
Accounts Payable   5.3  (6.5)
Accrued Taxes, Net   (201.9) (65.3)
Other Current Assets   7.9  0.5 
Other Current Liabilities   (15.7) 2.6 
Net Cash Flows from Operating Activities   565.3  573.1 
 
INVESTING ACTIVITIES      
Construction Expenditures   (786.9) (657.8)
Change in Advances to Affiliates, Net   (37.5) (208.1)
Other Investing Activities   21.7  11.3 
Net Cash Flows Used for Investing Activities   (802.7) (854.6)
 
FINANCING ACTIVITIES    
Capital Contribution from Member   40.8  34.6 
Issuance of Long-term Debt – Nonaffiliated 419.0  445.7 
Retirement of Long-term Debt – Nonaffiliated (90.0) — 
Change in Advances from Affiliates, Net   (37.0) (127.8)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs 2,782.9  — 
Dividends Paid to Member (2,878.3) (71.0)
Net Cash Flows from Financing Activities   237.4  281.5 
 
Net Change in Cash and Cash Equivalents   —  — 
Cash and Cash Equivalents at Beginning of Period   —  — 
Cash and Cash Equivalents at End of Period   $ —  $ — 
 
SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts   $ 106.7  $ 96.9 
Net Cash Paid (Received) for Income Taxes   (21.1) (12.5)
Construction Expenditures Included in Current Liabilities as of June 30,   218.9  237.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
61

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
  Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2025 2024 2025 2024
  (in millions of KWhs)
Retail:        
Residential 2,032  2,085  5,686  5,350 
Commercial 1,465  1,454  2,965  2,929 
Industrial 2,204  2,203  4,280  4,305 
Miscellaneous 208  203  419  414 
Total Retail 5,909  5,945  13,350  12,998 
Wholesale (a) 576  564  1,303  1,218 
Total KWhs 6,485  6,509  14,653  14,216 
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.


Summary of Heating and Cooling Degree Days
  Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2025 2024 2025 2024
  (in degree days)
Actual – Heating 69  48  1,433  1,029 
Normal – Heating 80  85  1,359  1,395 
Actual – Cooling 417  535  428  537 
Normal – Cooling 387  378  393  384 

62

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

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Retail Revenues increased $20 million primarily due to the following:
•A $10 million increase in fuel revenues.
•A $7 million increase in weather-normalized margins primarily in the residential and commercial classes.
•A $7 million increase in rider revenues.
These increases were partially offset by:
•A $7 million decrease in weather-related usage primarily due to a 22% decrease in cooling degree days.
•Transmission Revenues increased $14 million primarily due to the following:
•A $10 million increase due to continued transmission investment.
•A $6 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $14 million primarily due to the impact to the West Virginia ENEC as a result of the June 2025 FERC NOLC order.
•Other Operation and Maintenance expenses increased $5 million primarily due to the following:
•A $24 million increase in transmission expenses primarily due to:
•A $15 million increase due to the June 2025 FERC NOLC order.
•A $5 million increase in recoverable expenses.
•A $5 million increase in vegetation management expenses.
•A $6 million increase due to recoverable energy assistance program expenses for qualified Virginia customers.
63

These increases were partially offset by:
•A $23 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.
•Depreciation and Amortization expenses increased $25 million primarily due to a higher depreciable base.
•Income Tax Expense decreased $26 million primarily due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

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

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

•Retail Revenues increased $107 million primarily due to the following:
•A $35 million increase in fuel revenues.
•A $34 million increase in weather-related usage primarily due to a 39% increase in heating degree days, partially offset by a 20% decrease in cooling degree days.
•A $30 million increase in rider revenues.
•Transmission Revenues increased $16 million primarily due to the following:
•A $12 million increase due to continued transmission investment.
•A $6 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•Other Revenues decreased $6 million primarily due to a decrease in sales of renewable energy credits.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $4 million primarily due to the following:
•An $18 million decrease due to the prior year amortization of Excess ADIT through the West Virginia ENEC.
•A $17 million decrease due to the impact to the West Virginia ENEC as a result of the June 2025 FERC NOLC order.
These decreases were partially offset by:
•A $27 million increase in load and purchased power prices as well as an increase in West Virginia ENEC rates resulting in higher amortization of deferred fuel regulatory assets.
•Other Operation and Maintenance expenses increased $12 million primarily due to the following:
•A $27 million increase in transmission expenses primarily due to:
•A $15 million increase due to the June 2025 FERC NOLC order.
•A $7 million increase in recoverable expenses.
•A $5 million increase in vegetation management and Virginia storm-related expenses.
•A $14 million increase due to recoverable energy assistance program expenses for qualified Virginia customers.
These increases were partially offset by:
•A $25 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.
•Depreciation and Amortization expenses increased $38 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes decreased $9 million primarily due to lower business and occupation taxes.
•Income Tax Expense remained consistent primarily due to the following:
•A $16 million increase due to an increase in pretax book income.
•A $13 million increase due to a decrease in amortization of Excess ADIT.
These increases were partially offset by:
•A $23 million decrease due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $5 million decrease due to an increase in flow-through cost of removal.






64


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
  2025 2024 2025 2024
REVENUES        
Electric Generation, Transmission and Distribution $ 876.2  $ 851.7  $ 1,973.7  $ 1,876.0 
Sales to AEP Affiliates 66.2  54.8  138.2  117.9 
Other Revenues 5.2  3.7  8.6  9.3 
TOTAL REVENUES 947.6  910.2  2,120.5  2,003.2 
EXPENSES        
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 290.8  304.8  698.0  701.6 
Other Operation 210.8  212.0  433.0  424.6 
Maintenance 84.4  78.3  162.1  158.3 
Depreciation and Amortization 170.8  145.7  333.8  295.5 
Taxes Other Than Income Taxes 38.8  42.2  79.3  88.2 
TOTAL EXPENSES 795.6  783.0  1,706.2  1,668.2 
OPERATING INCOME 152.0  127.2  414.3  335.0 
Other Income (Expense):        
Interest Income 1.7  1.2  2.7  2.0 
Allowance for Equity Funds Used During Construction 4.2  4.3  8.6  7.2 
Non-Service Cost Components of Net Periodic Benefit Cost 5.3  6.4  10.5  13.5 
Interest Expense (70.0) (68.1) (137.6) (136.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 93.2  71.0  298.5  221.5 
Income Tax Expense (Benefit) (13.7) 12.7  27.0  26.7 
NET INCOME $ 106.9  $ 58.3  $ 271.5  $ 194.8 
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
65

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
2025 2024 2025 2024
Net Income $ 106.9  $ 58.3  $ 271.5  $ 194.8 
OTHER COMPREHENSIVE LOSS, NET OF TAXES    
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $(0.1) and $(0.1) for the Six Months Ended June 30, 2025 and 2024, Respectively
 (0.2) (0.2) (0.4) (0.4)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $0 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $(0.1) and $(0.1) for the Six Months Ended June 30, 2025 and 2024, Respectively
 (0.1) (0.3) (0.2) (0.6)
TOTAL OTHER COMPREHENSIVE LOSS (0.3) (0.5) (0.6) (1.0)
TOTAL COMPREHENSIVE INCOME $ 106.6  $ 57.8  $ 270.9  $ 193.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
66

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

67

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
June 30, December 31,
2025 2024
CURRENT ASSETS    
Cash and Cash Equivalents $ 6.2  $ 3.9 
Restricted Cash for Securitized Funding 18.2  16.2 
Advances to Affiliates 18.1  17.7 
Accounts Receivable:    
Customers 192.7  185.7 
Affiliated Companies 114.5  110.5 
Accrued Unbilled Revenues 76.0  93.1 
Miscellaneous 0.9  0.3 
Allowance for Credit Losses (2.2) (2.0)
Total Accounts Receivable 381.9  387.6 
Fuel 267.8  308.0 
Materials and Supplies 133.9  131.7 
Risk Management Assets 108.7  35.7 
Regulatory Asset for Under-Recovered Fuel Costs 128.3  148.1 
Prepayments and Other Current Assets 25.0  46.0 
TOTAL CURRENT ASSETS 1,088.1  1,094.9 
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 7,257.8  7,272.6 
Transmission 5,106.1  5,001.5 
Distribution 5,762.6  5,568.5 
Other Property, Plant and Equipment 1,145.5  1,062.9 
Construction Work in Progress 775.1  742.6 
Total Property, Plant and Equipment 20,047.1  19,648.1 
Accumulated Depreciation and Amortization 6,212.0  6,035.6 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 13,835.1  13,612.5 
OTHER NONCURRENT ASSETS    
Regulatory Assets 1,451.3  1,366.0 
Securitized Assets 92.2  106.2 
Employee Benefits and Pension Assets 211.8  203.9 
Operating Lease Assets 69.1  67.0 
Deferred Charges and Other Noncurrent Assets 174.4  215.4 
TOTAL OTHER NONCURRENT ASSETS 1,998.8  1,958.5 
TOTAL ASSETS $ 16,922.0  $ 16,665.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
68

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
June 30, 2025 and December 31, 2024
(Unaudited)
  June 30, December 31,
  2025 2024
  (in millions)
CURRENT LIABILITIES    
Advances from Affiliates $ 172.9  $ 95.0 
Accounts Payable:    
General 392.6  427.2 
Affiliated Companies 136.7  205.9 
Long-term Debt Due Within One Year – Nonaffiliated 271.1  798.6 
Customer Deposits 98.8  86.6 
Accrued Taxes 127.9  168.8 
Obligations Under Operating Leases 14.9  13.7 
Other Current Liabilities 181.0  229.7 
TOTAL CURRENT LIABILITIES 1,395.9  2,025.5 
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 5,500.9  4,861.7 
Deferred Income Taxes 2,079.8  2,033.5 
Regulatory Liabilities and Deferred Investment Tax Credits 1,070.1  1,115.8 
Asset Retirement Obligations 785.1  767.4 
Employee Benefits and Pension Obligations 28.0  29.6 
Obligations Under Operating Leases 54.7  54.0 
Deferred Credits and Other Noncurrent Liabilities 31.4  30.4 
TOTAL NONCURRENT LIABILITIES 9,550.0  8,892.4 
TOTAL LIABILITIES 10,945.9  10,917.9 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY    
Common Stock – No Par Value:
    
Authorized – 30,000,000 Shares
    
 Outstanding – 13,499,500 Shares
 260.4  260.4 
Paid-in Capital 1,951.3  1,944.1 
Retained Earnings 3,753.7  3,532.2 
Accumulated Other Comprehensive Income (Loss) 10.7  11.3 
TOTAL COMMON SHAREHOLDER’S EQUITY 5,976.1  5,748.0 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 16,922.0  $ 16,665.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
69

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Six Months Ended June 30,
  2025 2024
OPERATING ACTIVITIES    
Net Income $ 271.5  $ 194.8 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 333.8  295.5 
Deferred Income Taxes (4.5) (27.4)
Allowance for Equity Funds Used During Construction (8.6) (7.2)
Mark-to-Market of Risk Management Contracts (72.6) (54.4)
Deferred Fuel Over/Under-Recovery, Net 6.4  81.2 
Change in Regulatory Assets (117.6) 1.2 
Change in Other Noncurrent Assets 28.5  (0.7)
Change in Other Noncurrent Liabilities 6.4  5.9 
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net 5.7  (32.2)
Fuel, Materials and Supplies 38.0  45.4 
Margin Deposits 17.9  (12.4)
Accounts Payable (60.9) 66.4 
Accrued Taxes, Net (38.6) 41.6 
Other Current Assets (0.1) 2.3 
Other Current Liabilities (19.1) 10.8 
Net Cash Flows from Operating Activities 386.2  610.8 
INVESTING ACTIVITIES    
Construction Expenditures (527.6) (443.5)
Change in Advances to Affiliates, Net (0.4) (23.6)
Other Investing Activities 4.0  9.1 
Net Cash Flows Used for Investing Activities (524.0) (458.0)
FINANCING ACTIVITIES    
Capital Contribution from Parent 7.2  109.5 
Issuance of Long-term Debt – Nonaffiliated 528.2  480.8 
Change in Advances from Affiliates, Net 77.9  (339.6)
Retirement of Long-term Debt – Nonaffiliated (418.4) (399.5)
Principal Payments for Finance Lease Obligations (4.3) (4.4)
Dividends Paid on Common Stock (50.0) — 
Other Financing Activities 1.5  0.4 
Net Cash Flows from (Used for) Financing Activities 142.1  (152.8)
Net Increase in Cash, Cash Equivalents and Restricted Cash for Securitized Funding 4.3  — 
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 20.1  19.9 
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $ 24.4  $ 19.9 
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $ 134.4  $ 126.6 
Net Cash Paid (Received) for Income Taxes (18.5) 9.6 
Cash Paid (Received) for Transferable Tax Credits —  (0.1)
Noncash Acquisitions Under Finance Leases 2.2  0.7 
Construction Expenditures Included in Current Liabilities as of June 30, 115.4  143.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
70

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
  Three Months Ended 
June 30,		 Six Months Ended 
June 30,
  2025 2024 2025 2024
  (in millions of KWhs)
Retail:        
Residential 1,097  1,162  2,650  2,600 
Commercial 1,414  1,290  2,686  2,565 
Industrial 1,856  1,853  3,604  3,661 
Miscellaneous 9  11  22  25 
Total Retail 4,376  4,316  8,962  8,851 
Wholesale (a) 1,507  1,117  3,943  2,737 
Total KWhs 5,883  5,433  12,905  11,588 
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.


Summary of Heating and Cooling Degree Days
  Three Months Ended 
June 30,		 Six Months Ended 
June 30,
  2025 2024 2025 2024
  (in degree days)
Actual – Heating 217  141  2,335  1,826 
Normal – Heating 237  241  2,365  2,422 
Actual – Cooling 280  357  280  357 
Normal – Cooling 284  268  285  269 
71

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

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Retail Revenues increased $83 million primarily due to the following:
•A $35 million increase due to the implementation of new base rates in Indiana and Michigan.
•A $34 million increase in weather-normalized margins primarily in the commercial class.
•A $23 million increase in rider revenues.
•A $20 million increase in fuel revenues.
These increases were partially offset by:
•A $22 million decrease due to regulatory provisions for refund.
•A $6 million decrease in weather-related usage primarily due to a 21% decrease in cooling degree days.
•Off-system Sales increased $57 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales.
•Transmission Revenues increased $10 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•Other Revenues decreased $7 million primarily due to a decrease in River Transportation Division (RTD) barging revenues.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $46 million primarily due to an increase in recoverable fuel and purchased power costs and an increase in Rockport Plant, Unit 2 merchant generation fuel costs.
•Purchased Electricity from AEP Affiliates increased $22 million primarily due to an increase in purchased electricity from AEGCo.
72

•Other Operation and Maintenance expenses increased $12 million primarily due to the following:
•A $21 million increase in vegetation management expenses.
•A $6 million increase in nuclear expenses at Cook Plant.
These increases were partially offset by:
•A $12 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.
•A $6 million decrease in demand side management expenses.
•Asset Impairments and Other Related Charges decreased $13 million due to the Federal EPA’s revised CCR rules finalized in 2024.
•Depreciation and Amortization expenses increased $10 million primarily due to the following:
•A $5 million increase due to a higher depreciable base.
•A $3 million increase in regulatory reserves related to Nuclear PTCs.
•Income Tax Benefit increased $23 million primarily due to the following:
•A $32 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•An $18 million increase due to an increase in deferred ITC amortization and PTCs.
These increases were partially offset by:
•A $14 million decrease due to an increase in pretax book income.
•A $13 million decrease in amortization of Excess ADIT.

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

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

•Retail Revenues increased $133 million primarily due to the following:
•A $78 million increase due to the implementation of new base rates in Indiana and Michigan.
•A $61 million increase in fuel revenues.
•A $35 million increase in weather-normalized margins primarily in the residential and commercial classes, partially offset by a decrease in the industrial class.
•A $16 million increase in rider revenues.
•A $7 million increase in weather-related usage primarily due to a 28% increase in heating degree days.
These increases were partially offset by:
•A $71 million decrease due to regulatory provisions for refund.
•Off-system Sales increased $63 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales.
•Transmission Revenues increased $11 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•Other Revenues decreased $9 million primarily due to the following:
•A $6 million decrease in RTD barging revenues.
•A $4 million decrease in sales of renewable energy credits.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $100 million primarily due to an increase in recoverable fuel and purchased power costs and an increase in Rockport Plant, Unit 2, merchant generation fuel costs, partially offset by a decrease due to a prior year purchased power disallowance from the MPSC order on the 2021 PSCR reconciliation.
•Purchased Electricity from AEP Affiliates increased $36 million primarily due to an increase in purchased electricity from AEGCo.
•Other Operation and Maintenance expenses increased $12 million primarily due to the following:
•A $28 million increase in distribution expenses primarily due to an increase in vegetation management costs.
•A $7 million increase in transmission expenses primarily due to an $11 million increase in recoverable PJM expenses, partially offset by a $5 million decrease primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
These increases were partially offset by:
•A $13 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.
•A $12 million decrease in demand side management expenses.
73

•Asset Impairments and Other Related Charges decreased $13 million due to the Federal EPA’s revised CCR rules finalized in 2024.
•Depreciation and Amortization expenses increased $26 million primarily due to the following:
•A $9 million increase due to a higher depreciable base.
•A $9 million increase due to a prior year deferral of Excess ADIT as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs.
•A $5 million increase in regulatory reserves related to Nuclear PTCs.
•Interest Expense increased $11 million primarily due to a prior year deferral of expenses as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.
•Income Tax Benefit decreased $24 million primarily due to the following:
•A $55 million decrease due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking recorded in 2024.
•A $17 million decrease in amortization of Excess ADIT.
•A $5 million decrease due to an increase in pretax book income.
These decreases were partially offset by:
•A $32 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•A $24 million increase due to an increase in PTCs.

74


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
  2025 2024 2025 2024
REVENUES        
Electric Generation, Transmission and Distribution $ 735.6  $ 574.9  $ 1,494.7  $ 1,232.3 
Sales to AEP Affiliates 1.5  5.4  5.4  7.7 
(Provision for)/Reversal of – Revenue Refund – Affiliated 9.2  (3.3) 8.5  (3.8)
Provision for Refund – Nonaffiliated (25.7) (5.3) (83.9) (14.9)
Other Revenues – Affiliated 14.4  20.5  29.9  35.5 
Other Revenues – Nonaffiliated 2.2  2.1  4.8  4.9 
TOTAL REVENUES 737.2  594.3  1,459.4  1,261.7 
EXPENSES        
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 132.4  86.1  308.2  208.7 
Purchased Electricity from AEP Affiliates 66.4  44.5  142.4  106.0 
Other Operation 177.5  190.3  348.4  368.5 
Maintenance 87.8  63.2  147.9  115.6 
Asset Impairments and Other Related Charges —  13.4  —  13.4 
Depreciation and Amortization 128.7  118.3  252.7  226.6 
Taxes Other Than Income Taxes 21.6  24.6  47.8  47.9 
TOTAL EXPENSES 614.4  540.4  1,247.4  1,086.7 
OPERATING INCOME 122.8  53.9  212.0  175.0 
Other Income (Expense):        
Other Income 3.8  3.2  8.4  6.4 
Non-Service Cost Components of Net Periodic Benefit Cost 5.2  6.5  10.4  13.2 
Interest Expense (38.9) (37.0) (73.7) (63.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 92.9  26.6  157.1  131.4 
Income Tax Expense (Benefit) (31.2) (8.6) (24.5) (48.8)
NET INCOME $ 124.1  $ 35.2  $ 181.6  $ 180.2 
The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
75

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
2025 2024 2025 2024
Net Income $ 124.1  $ 35.2  $ 181.6  $ 180.2 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES      
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $0.1 and $0.1 for the Six Months Ended June 30, 2025 and 2024, Respectively
 0.1  0.1  0.2  0.2 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $0 and $0 for the Six Months Ended June 30, 2025 and 2024, Respectively
 0.1  (0.1) 0.1  (0.1)
TOTAL OTHER COMPREHENSIVE INCOME 0.2  —  0.3  0.1 
TOTAL COMPREHENSIVE INCOME $ 124.3  $ 35.2  $ 181.9  $ 180.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
76

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2023
 $ 56.6  $ 997.6  $ 2,086.6  $ (0.6) $ 3,140.2 
Common Stock Dividends     (37.5)   (37.5)
Net Income     145.0    145.0 
Other Comprehensive Income       0.1  0.1 
TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 2024 56.6  997.6  2,194.1  (0.5) 3,247.8 
Capital Contribution from Parent 5.0  5.0 
Common Stock Dividends (37.5) (37.5)
Net Income 35.2  35.2 
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2024 $ 56.6  $ 1,002.6  $ 2,191.8  $ (0.5) $ 3,250.5 
         
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2024
 $ 56.6  $ 1,011.7  $ 2,328.0  $ 0.2  $ 3,396.5 
Common Stock Dividends (50.0) (50.0)
Net Income 57.5  57.5 
Other Comprehensive Income 0.1  0.1 
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2025 56.6  1,011.7  2,335.5  0.3  3,404.1 
Capital Contribution from Parent 7.4  7.4 
Net Income     124.1    124.1 
Other Comprehensive Income       0.2  0.2 
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2025 $ 56.6  $ 1,019.1  $ 2,459.6  $ 0.5  $ 3,535.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
77

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
June 30, December 31,
  2025 2024
CURRENT ASSETS    
Cash and Cash Equivalents $ 3.5  $ 1.5 
Accounts Receivable:    
Customers 62.6  58.7 
Affiliated Companies 81.6  79.1 
Accrued Unbilled Revenues 25.5  21.4 
Miscellaneous 5.3  6.3 
Total Accounts Receivable 175.0  165.5 
Fuel 54.6  83.4 
Materials and Supplies 214.9  212.2 
Risk Management Assets 12.3  18.4 
Regulatory Asset for Under-Recovered Fuel Costs 5.0  10.6 
Prepayments and Other Current Assets 60.2  52.0 
TOTAL CURRENT ASSETS 525.5  543.6 
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 5,460.1  5,503.0 
Transmission 1,978.1  1,957.8 
Distribution 3,692.0  3,535.0 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 1,062.9  992.4 
Construction Work in Progress 390.1  334.9 
Total Property, Plant and Equipment 12,583.2  12,323.1 
Accumulated Depreciation, Depletion and Amortization 4,786.8  4,643.8 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 7,796.4  7,679.3 
OTHER NONCURRENT ASSETS    
Regulatory Assets 616.1  548.1 
Spent Nuclear Fuel and Decommissioning Trusts 4,609.7  4,395.1 
Operating Lease Assets 59.0  51.5 
Deferred Charges and Other Noncurrent Assets 290.1  317.9 
TOTAL OTHER NONCURRENT ASSETS 5,574.9  5,312.6 
TOTAL ASSETS $ 13,896.8  $ 13,535.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
78

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
June 30, 2025 and December 31, 2024
(dollars in millions)
(Unaudited)
  June 30, December 31,
  2025 2024
CURRENT LIABILITIES    
Advances from Affiliates $ 25.7  $ 126.8 
Accounts Payable:    
General 250.3  202.2 
Affiliated Companies 94.3  98.5 
Long-term Debt Due Within One Year – Nonaffiliated
   (June 30, 2025 and December 31, 2024 Amounts Include $94.6 and $79.0,
   Respectively, Related to DCC Fuel)
 94.6  269.2 
Customer Deposits 54.6  59.1 
Accrued Taxes 101.5  102.2 
Accrued Interest 41.6  41.3 
Obligations Under Operating Leases 14.9  12.3 
Regulatory Liability for Over-Recovered Fuel Costs 13.5  10.3 
Other Current Liabilities 162.9  149.3 
TOTAL CURRENT LIABILITIES 853.9  1,071.2 
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 3,416.3  3,225.1 
Deferred Income Taxes 1,185.1  1,175.8 
Regulatory Liabilities and Deferred Investment Tax Credits 2,636.3  2,480.8 
Asset Retirement Obligations 2,135.0  2,088.8 
Obligations Under Operating Leases 45.0  40.1 
Deferred Credits and Other Noncurrent Liabilities 89.4  57.2 
TOTAL NONCURRENT LIABILITIES 9,507.1  9,067.8 
TOTAL LIABILITIES 10,361.0  10,139.0 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY    
Common Stock – No Par Value:
    
Authorized – 2,500,000 Shares
    
Outstanding – 1,400,000 Shares
 56.6  56.6 
Paid-in Capital 1,019.1  1,011.7 
Retained Earnings 2,459.6  2,328.0 
Accumulated Other Comprehensive Income (Loss) 0.5  0.2 
TOTAL COMMON SHAREHOLDER’S EQUITY 3,535.8  3,396.5 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 13,896.8  $ 13,535.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
79

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Six Months Ended June 30,
  2025 2024
OPERATING ACTIVITIES    
Net Income $ 181.6  $ 180.2 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization 252.7  226.6 
Deferred Income Taxes (45.7) (69.8)
Deferral of Incremental Nuclear Refueling Outage Expenses, Net (22.8) (20.5)
Asset Impairments and Other Related Charges —  13.4 
Allowance for Equity Funds Used During Construction (8.1) (6.7)
Mark-to-Market of Risk Management Contracts 6.6  9.5 
Amortization of Nuclear Fuel 51.8  46.1 
Deferred Fuel Over/Under-Recovery, Net 8.8  (9.5)
Change in Other Noncurrent Assets (13.9) 10.2 
Change in Other Noncurrent Liabilities 55.3  29.3 
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net (9.5) (0.1)
Fuel, Materials and Supplies 26.1  8.6 
Accounts Payable 27.8  (7.5)
Accrued Taxes, Net (0.7) 36.1 
Other Current Assets 2.5  (8.8)
Other Current Liabilities (13.6) (10.8)
Net Cash Flows from Operating Activities 498.9  426.3 
INVESTING ACTIVITIES    
Construction Expenditures (305.7) (275.0)
Purchases of Investment Securities (1,330.0) (1,187.1)
Sales of Investment Securities 1,294.4  1,154.1 
Acquisitions of Nuclear Fuel (45.6) (69.8)
Other Investing Activities 27.2  3.7 
Net Cash Flows Used for Investing Activities (359.7) (374.1)
FINANCING ACTIVITIES    
Capital Contribution from Parent 7.4  5.0 
Issuance of Long-term Debt – Nonaffiliated 249.0  80.4 
Change in Advances from Affiliates, Net (101.1) (10.7)
Retirement of Long-term Debt – Nonaffiliated (240.0) (48.6)
Principal Payments for Finance Lease Obligations (3.1) (3.6)
Dividends Paid on Common Stock (50.0) (75.0)
Other Financing Activities 0.6  0.6 
Net Cash Flows Used for Financing Activities (137.2) (51.9)
Net Increase in Cash and Cash Equivalents 2.0  0.3 
Cash and Cash Equivalents at Beginning of Period 1.5  2.1 
Cash and Cash Equivalents at End of Period $ 3.5  $ 2.4 
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $ 71.5  $ 72.8 
Net Cash Paid (Received) for Income Taxes 2.9  (14.5)
Noncash Acquisitions Under Finance Leases 1.4  1.0 
Construction Expenditures Included in Current Liabilities as of June 30, 81.8  86.2 
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 33.4  8.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
80

OHIO POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
  Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2025 2024 2025 2024
  (in millions of KWhs)
Retail:        
Residential 3,024  3,064  7,119  6,815 
Commercial 6,323  5,066  11,812  9,750 
Industrial 3,748  3,502  7,134  7,041 
Miscellaneous 25  24  53  53 
Total Retail (a) 13,120  11,656  26,118  23,659 
Wholesale (b) 464  253  1,131  843 
Total KWhs 13,584  11,909  27,249  24,502 

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


Summary of Heating and Cooling Degree Days
  Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2025 2024 2025 2024
  (in degree days)
Actual – Heating 170  110  2,077  1,573 
Normal – Heating 173  181  1,993  2,052 
Actual – Cooling 336  422  342  422 
Normal – Cooling 323  306  325  309 
81

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

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Retail Revenues increased $14 million primarily due to the following:
•A $24 million increase in weather-normalized revenues primarily in the commercial and industrial classes.
•An $8 million increase in rider revenues.
These increases were partially offset by:
•An $11 million decrease due to lower prices and lower customer participation in OPCo’s SSO.
•A $5 million decrease in weather-related usage driven by a 20% decrease in cooling degree days.
•Off-system Sales increased $13 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.
•Other Revenues decreased $8 million primarily due to lower third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

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

•Purchased Electricity from AEP Affiliates expenses decreased $11 million primarily due to decreased recoverable purchases to serve SSO customers.
82

•Other Operation and Maintenance expenses decreased $5 million primarily due to the following:
•A $13 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.
•A $9 million decrease related to recoverable energy assistance program expenses for qualified Ohio customers.
These decreases were partially offset by:
•An $8 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
•An $8 million increase in distribution expenses primarily related to recoverable storm restoration costs and recoverable vegetation management expenses.
•Asset Impairments and Other Related Charges decreased $53 million primarily due to the Federal EPA’s revised CCR rules finalized in 2024.
•Depreciation and Amortization expenses decreased $7 million primarily due to capital rider under-recoveries.
•Taxes Other Than Income Taxes decreased $17 million primarily due to the following:
•A $12 million decrease in property taxes.
•A $6 million decrease in state excise taxes due to decreased billed KWhs in 2025.
•Income Tax Expense increased $26 million primarily due to an increase in pretax book income.

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

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

•Retail Revenues decreased $18 million primarily due to the following:
•An $88 million decrease due to lower prices and lower customer participation in OPCo’s SSO.
•A $4 million decrease in weather-normalized revenues primarily in the residential class partially offset by an increase in the commercial class.
These decreases were partially offset by:
•A $57 million increase in rider revenues.
•A $22 million increase in weather-related usage driven by a 32% increase in heating degree days.
•Off-system Sales increased $26 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.
•Transmission Revenues increased $6 million primarily due to continued transmission investment.
•Other Revenues decreased $12 million primarily due to the following:
•A $7 million decrease in recoverable sales of renewable energy credits.
•A $5 million decrease due to lower third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

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

•Purchased Electricity for Resale expenses decreased $8 million primarily due to the following:
•A $41 million decrease in recoverable auction purchases primarily due to lower prices.
•A $12 million decrease in recoverable alternative energy rider expenses.
These decreases were partially offset by:
•A $30 million estimated reduction in regulatory assets for OVEC-related purchased power costs that are no longer probable of future recovery due to recently approved legislation in Ohio.
•A $17 million increase in recoverable OVEC costs.
•Purchased Electricity from AEP Affiliates expenses decreased $41 million primarily due to decreased recoverable purchases to serve SSO customers.
•Other Operation and Maintenance expenses increased $27 million primarily due to the following:
•A $58 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
This increase was partially offset by:
•A $19 million decrease related to recoverable energy assistance program expenses for qualified Ohio customers.
•A $12 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.
•Asset Impairments and Other Related Charges decreased $53 million primarily due to the Federal EPA’s revised CCR rules finalized in 2024.
•Depreciation and Amortization expenses decreased $19 million primarily due to capital rider under-recoveries.
•Taxes Other Than Income Taxes decreased $9 million primarily due to lower property taxes.
•Interest Expense increased $7 million primarily due to higher debt balances.
•Income Tax Expense increased $26 million primarily due to an increase in pretax book income.
83


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Three Months Ended Six Months Ended
June 30, June 30,
  2025 2024 2025 2024
REVENUES        
Electricity, Transmission and Distribution $ 910.1  $ 887.8  $ 1,900.3  $ 1,903.2 
Sales to AEP Affiliates 6.3  5.7  16.0  11.4 
Other Revenues 2.6  2.8  6.2  5.5 
TOTAL REVENUES 919.0  896.3  1,922.5  1,920.1 
EXPENSES        
Purchased Electricity for Resale 188.9  185.0  435.8  443.7 
Purchased Electricity from AEP Affiliates 14.8  25.5  30.7  72.1 
Other Operation 283.3  283.8  617.0  577.0 
Maintenance 63.0  67.1  115.6  128.4 
Asset Impairments and Other Related Charges —  52.9  —  52.9 
Depreciation and Amortization 94.8  102.0  188.7  207.8 
Taxes Other Than Income Taxes 120.3  137.3  279.0  288.1 
TOTAL EXPENSES 765.1  853.6  1,666.8  1,770.0 
OPERATING INCOME 153.9  42.7  255.7  150.1 
Other Income (Expense):        
Other Income —  0.9  0.9  0.9 
Allowance for Equity Funds Used During Construction 7.1  4.3  14.1  9.8 
Non-Service Cost Components of Net Periodic Benefit Cost 4.3  5.3  8.6  10.8 
Interest Expense (39.6) (36.6) (78.0) (71.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS 125.7  16.6  201.3  100.4 
Income Tax Expense (Benefit) 23.0  (2.6) 36.9  10.6 
Equity Earnings of Unconsolidated Subsidiaries 0.1  (0.8) 1.4  (0.8)
NET INCOME $ 102.8  $ 18.4  $ 165.8  $ 89.0 
The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
84

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2023
 $ 321.2  $ 1,012.8  $ 2,237.3  $ 3,571.3 
Net Income 70.6  70.6 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2024
 321.2  1,012.8  2,307.9  3,641.9 
Net Income     18.4  18.4 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2024
 $ 321.2  $ 1,012.8  $ 2,326.3  $ 3,660.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024
 $ 321.2  $ 1,020.0  $ 2,542.9  $ 3,884.1 
Common Stock Dividends (46.0) (46.0)
Net Income 63.0  63.0 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2025
 321.2  1,020.0  2,559.9  3,901.1 
Capital Contribution from Parent 1.8  1.8 
Common Stock Dividends     (25.0) (25.0)
Net Income     102.8  102.8 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2025
 $ 321.2  $ 1,021.8  $ 2,637.7  $ 3,980.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
85

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
  June 30, December 31,
  2025 2024
CURRENT ASSETS    
Cash and Cash Equivalents $ 8.2  $ 4.5 
Advances to Affiliates —  114.9 
Accounts Receivable:    
Customers 167.3  189.2 
Affiliated Companies 120.8  117.5 
Accrued Unbilled Revenues 51.2  31.1 
Miscellaneous 4.7  8.6 
Total Accounts Receivable 344.0  346.4 
Materials and Supplies 177.7  141.4 
Prepayments and Other Current Assets 12.1  19.9 
TOTAL CURRENT ASSETS 542.0  627.1 
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Transmission 3,744.8  3,663.9 
Distribution 7,389.7  7,244.0 
Other Property, Plant and Equipment 1,258.6  1,256.0 
Construction Work in Progress 818.9  691.1 
Total Property, Plant and Equipment 13,212.0  12,855.0 
Accumulated Depreciation and Amortization 2,945.7  2,883.9 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 10,266.3  9,971.1 
OTHER NONCURRENT ASSETS    
Regulatory Assets 364.1  379.1 
Operating Lease Assets 55.6  60.4 
Deferred Charges and Other Noncurrent Assets 408.9  661.0 
TOTAL OTHER NONCURRENT ASSETS 828.6  1,100.5 
TOTAL ASSETS $ 11,636.9  $ 11,698.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
86

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
June 30, 2025 and December 31, 2024
(Unaudited)
  June 30, December 31,
  2025 2024
(in millions)
CURRENT LIABILITIES    
Advances from Affiliates $ 203.0  $ — 
Accounts Payable:    
General 340.2  343.6 
Affiliated Companies 169.4  204.9 
Risk Management Liabilities 5.9  7.3 
Customer Deposits 92.8  108.1 
Accrued Taxes 529.8  836.1 
Obligations Under Operating Leases 12.0  12.3 
Other Current Liabilities 166.5  182.2 
TOTAL CURRENT LIABILITIES 1,519.6  1,694.5 
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 3,717.1  3,715.7 
Long-term Risk Management Liabilities 41.8  40.2 
Deferred Income Taxes 1,225.1  1,201.1 
Regulatory Liabilities and Deferred Investment Tax Credits 917.9  987.7 
Obligations Under Operating Leases 43.9  48.4 
Deferred Credits and Other Noncurrent Liabilities 190.8  127.0 
TOTAL NONCURRENT LIABILITIES 6,136.6  6,120.1 
TOTAL LIABILITIES 7,656.2  7,814.6 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY    
Common Stock –No Par Value:
    
Authorized – 40,000,000 Shares
    
Outstanding – 27,952,473 Shares
 321.2  321.2 
Paid-in Capital 1,021.8  1,020.0 
Retained Earnings 2,637.7  2,542.9 
TOTAL COMMON SHAREHOLDER’S EQUITY 3,980.7  3,884.1 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 11,636.9  $ 11,698.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
87

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Six Months Ended June 30,
  2025 2024
OPERATING ACTIVITIES    
Net Income $ 165.8  $ 89.0 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 188.7  207.8 
Deferred Income Taxes 13.7  (10.2)
Asset Impairments and Other Related Charges —  52.9 
Allowance for Equity Funds Used During Construction (14.1) (9.8)
Mark-to-Market of Risk Management Contracts 0.2  (7.5)
Property Taxes 205.8  190.8 
Change in Other Noncurrent Assets 41.3  4.8 
Change in Other Noncurrent Liabilities (9.0) 18.4 
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net 2.4  (80.4)
Materials and Supplies (19.0) 9.7 
Accounts Payable (4.9) (47.2)
Customer Deposits (15.3) 39.0 
Accrued Taxes, Net (305.7) (207.1)
Other Current Assets 7.2  (4.9)
Other Current Liabilities (23.3) 11.1 
Net Cash Flows from Operating Activities 233.8  256.4 
INVESTING ACTIVITIES    
Construction Expenditures (504.3) (455.8)
Change in Advances to Affiliates, Net 114.9  (49.9)
Other Investing Activities 26.8  15.3 
Net Cash Flows Used for Investing Activities (362.6) (490.4)
FINANCING ACTIVITIES    
Capital Contribution from Parent 1.8  — 
Issuance of Long-term Debt – Nonaffiliated —  346.3 
Change in Advances from Affiliates, Net 203.0  (110.5)
Principal Payments for Finance Lease Obligations (2.3) (2.7)
Dividends Paid on Common Stock (71.0) — 
Other Financing Activities 1.0  0.8 
Net Cash Flows from Financing Activities 132.5  233.9 
Net Increase (Decrease) in Cash and Cash Equivalents 3.7  (0.1)
Cash and Cash Equivalents at Beginning of Period 4.5  6.4 
Cash and Cash Equivalents at End of Period $ 8.2  $ 6.3 
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $ 72.4  $ 64.6 
Net Cash Paid (Received) for Income Taxes 1.3  (13.0)
Noncash Acquisitions Under Finance Leases 1.1  0.8 
Construction Expenditures Included in Current Liabilities as of June 30, 121.3  112.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
88

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
  Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2025 2024 2025 2024
  (in millions of KWhs)
Retail:        
Residential 1,319  1,463  2,911  2,914 
Commercial 1,485  1,383  2,806  2,615 
Industrial 1,483  1,501  2,860  2,912 
Miscellaneous 325  327  604  610 
Total Retail 4,612  4,674  9,181  9,051 
Wholesale (a) 28  64  85  111 
Total KWhs 4,640  4,738  9,266  9,162 
(a)Includes municipalities and cooperatives, unit power and other wholesale customers.


Summary of Heating and Cooling Degree Days
  Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2025 2024 2025 2024
  (in degree days)
Actual – Heating 31  5  1,193  917 
Normal – Heating 43  42  1,081  1,088 
Actual – Cooling 605  808  629  830 
Normal – Cooling 709  665  729  682 
89

Public Service Company of Oklahoma
Reconciliation of 2024 to 2025 Net Income
(in millions)
Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2024 Net Income $ 36.3  $ 108.3 
Changes in Revenues:
Retail Revenues (a) 10.7  20.8 
Transmission Revenues 9.0  12.1 
Other Revenues (9.0) (16.0)
Total Change in Revenues 10.7  16.9 
Changes in Expenses and Other:  
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 7.7  27.6 
Other Operation and Maintenance (8.6) (13.2)
Depreciation and Amortization (3.0) (4.1)
Taxes Other Than Income Taxes 4.1  2.8 
Interest Income 0.1  1.8 
Allowance for Equity Funds Used During Construction 2.1  2.9 
Non-Service Cost Components of Net Periodic Benefit Cost (0.6) (1.4)
Interest Expense (2.1) (15.9)
Total Change in Expenses and Other (0.3) 0.5 
   
Income Tax Benefit 17.0  (34.5)
   
2025 Net Income $ 63.7  $ 91.2 

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

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Retail Revenues increased $11 million primarily due to the following:
•A $36 million increase in base rate and rider revenues.
•A $12 million increase in weather-normalized margins primarily in the residential class.
These increases were partially offset by:
•A $20 million decrease in weather-related usage primarily driven by a 25% decrease in cooling degree days.
•A $20 million decrease in fuel revenue primarily due to lower authorized fuel rates.
•Transmission Revenues increased $9 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
•Other Revenues decreased $9 million primarily due to revenues from a customer project to enhance transmission resiliency in 2024.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $8 million primarily due to increased fuel and purchased power costs, and lower authorized fuel rates resulting in lower current amortization of under-recovered deferred fuel regulatory assets.
•Other Operation and Maintenance expenses increased $9 million primarily due to the following:
•A $19 million increase in transmission-related expenses primarily due to the June 2025 FERC NOLC order.
•A $7 million increase in overhead line maintenance expenses.
90

These increases were partially offset by:
•A $10 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.
•A $9 million decrease in expenses from a customer project to enhance transmission resiliency in 2024.
•Income Tax Benefit increased $17 million primarily due to the following:
•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.
•A $7 million increase due to an increase in PTCs.

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

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

•Retail Revenues increased $21 million primarily due to the following:
•A $64 million increase in base rate and rider revenues.
•An $11 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 $50 million decrease in fuel revenue primarily due to lower authorized fuel rates.
•A $12 million decrease in weather-related usage primarily driven by a 24% decrease in cooling degree days.
•Transmission Revenues increased $12 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates and continued transmission investment.
•Other Revenues decreased $16 million primarily due to revenues from a customer project to enhance transmission resiliency in 2024.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $28 million primarily due to increased fuel and purchased power costs and lower authorized fuel rates resulting in increased deferred fuel balances.
•Other Operation and Maintenance expenses increased $13 million primarily due to the following:
•A $25 million increase in transmission-related expenses primarily due to the June 2025 FERC NOLC order and SPP expenses.
•A $10 million increase in overhead line maintenance expenses.
These increases were partially offset by:
•A $13 million decrease in expenses from a customer project to enhance transmission resiliency in 2024.
•A $10 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.
•Interest Expense increased $16 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 $35 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.
91


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
  June 30, June 30,
  2025 2024 2025 2024
REVENUES        
Electric Generation, Transmission and Distribution $ 466.5  $ 448.1  $ 856.0  $ 826.2 
Sales to AEP Affiliates 1.2  1.1  2.4  4.6 
Other Revenues 1.8  9.6  5.1  15.8 
TOTAL REVENUES 469.5  458.8  863.5  846.6 
EXPENSES        
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 172.3  180.0  301.3  328.9 
Other Operation 122.4  119.3  223.7  215.9 
Maintenance 30.4  24.9  58.4  53.0 
Depreciation and Amortization 67.1  64.1  135.6  131.5 
Taxes Other Than Income Taxes 20.3  24.4  38.6  41.4 
TOTAL EXPENSES 412.5  412.7  757.6  770.7 
OPERATING INCOME 57.0  46.1  105.9  75.9 
Other Income (Expense):        
Interest Income 0.4  0.3  2.3  0.5 
Allowance for Equity Funds Used During Construction 3.0  0.9  6.2  3.3 
Non-Service Cost Components of Net Periodic Benefit Cost 2.1  2.7  4.2  5.6 
Interest Expense (29.0) (26.9) (59.6) (43.7)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 33.5  23.1  59.0  41.6 
Income Tax Expense (Benefit) (30.2) (13.2) (32.2) (66.7)
NET INCOME $ 63.7  $ 36.3  $ 91.2  $ 108.3 
The common stock of PSO is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
92

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Three Months Ended Six Months Ended
June 30, June 30,
2025 2024 2025 2024
Net Income $ 63.7  $ 36.3  $ 91.2  $ 108.3 
OTHER COMPREHENSIVE LOSS, NET OF TAXES        
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $(0.3) and $0 for the Six Months Ended June 30, 2025 and 2024, Respectively
 —  —  (1.2) — 
       
TOTAL COMPREHENSIVE INCOME $ 63.7  $ 36.3  $ 90.0  $ 108.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
93

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2023 $ 157.2  $ 1,039.3  $ 1,374.3  $ (0.2) $ 2,570.6 
Common Stock Dividends (35.0) (35.0)
Net Income 72.0  72.0 
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2024 157.2  1,039.3  1,411.3  (0.2) 2,607.6 
Capital Contribution from Parent 0.2  0.2 
Common Stock Dividends (35.0) (35.0)
Net Income     36.3    36.3 
TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2024 $ 157.2  $ 1,039.5  $ 1,412.6  $ (0.2) $ 2,609.1 
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2024 $ 157.2  $ 1,041.2  $ 1,483.6  $ 3.6  $ 2,685.6 
Net Income 27.5  27.5 
Other Comprehensive Loss (1.2) (1.2)
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2025 157.2  1,041.2  1,511.1  2.4  2,711.9 
Capital Contribution from Parent 299.9  299.9 
Net Income     63.7    63.7 
TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2025 $ 157.2  $ 1,341.1  $ 1,574.8  $ 2.4  $ 3,075.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.

94

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
June 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
  June 30, December 31,
  2025 2024
CURRENT ASSETS    
Cash and Cash Equivalents $ 3.8  $ 1.8 
Advances to Affiliates —  232.0 
Accounts Receivable:    
Customers 86.4  74.8 
Affiliated Companies 59.8  32.6 
Miscellaneous 0.1  0.3 
Total Accounts Receivable 146.3  107.7 
Fuel 9.6  17.1 
Materials and Supplies 117.1  108.8 
Risk Management Assets 96.9  20.6 
Accrued Tax Benefits 35.3  35.5 
Regulatory Asset for Under-Recovered Fuel Costs 139.0  64.7 
Prepayments and Other Current Assets 35.7  20.2 
TOTAL CURRENT ASSETS 583.7  608.4 
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 3,990.3  2,772.4 
Transmission 1,368.6  1,345.3 
Distribution 3,851.7  3,698.8 
Other Property, Plant and Equipment 1,263.2  550.0 
Construction Work in Progress 390.5  378.8 
Total Property, Plant and Equipment 10,864.3  8,745.3 
Accumulated Depreciation and Amortization 2,660.7  2,213.0 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 8,203.6  6,532.3 
OTHER NONCURRENT ASSETS    
Regulatory Assets 551.9  527.8 
Employee Benefits and Pension Assets 76.6  73.6 
Operating Lease Assets 118.6  106.2 
Deferred Charges and Other Noncurrent Assets 70.7  62.0 
TOTAL OTHER NONCURRENT ASSETS 817.8  769.6 
TOTAL ASSETS $ 9,605.1  $ 7,910.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
95

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
June 30, 2025 and December 31, 2024
(Unaudited)
  June 30, December 31,
  2025 2024
  (in millions)
CURRENT LIABILITIES    
Advances from Affiliates $ 319.7  $ — 
Accounts Payable:    
General 329.7  200.5 
Affiliated Companies 59.6  59.1 
Long-term Debt Due Within One Year – Nonaffiliated 0.6  125.6 
Risk Management Liabilities 5.6  5.8 
Customer Deposits 83.1  72.9 
Accrued Taxes 78.8  33.4 
Accrued Interest 47.6  33.1 
Obligations Under Operating Leases 10.5  10.4 
Other Current Liabilities 78.1  78.6 
TOTAL CURRENT LIABILITIES 1,013.3  619.4 
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 3,523.4  2,730.0 
Deferred Income Taxes 995.7  930.6 
Regulatory Liabilities and Deferred Investment Tax Credits 698.2  689.7 
Asset Retirement Obligations 133.9  118.8 
Obligations Under Operating Leases 114.8  101.9 
Deferred Credits and Other Noncurrent Liabilities 50.3  34.3 
TOTAL NONCURRENT LIABILITIES 5,516.3  4,605.3 
TOTAL LIABILITIES 6,529.6  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 Capital 1,341.1  1,041.2 
Retained Earnings 1,574.8  1,483.6 
Accumulated Other Comprehensive Income (Loss) 2.4  3.6 
TOTAL COMMON SHAREHOLDER’S EQUITY 3,075.5  2,685.6 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 9,605.1  $ 7,910.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
96

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Six Months Ended June 30,
  2025 2024
OPERATING ACTIVITIES    
Net Income $ 91.2  $ 108.3 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 135.6  131.5 
Deferred Income Taxes 40.2  8.2 
Allowance for Equity Funds Used During Construction (6.2) (3.3)
Mark-to-Market of Risk Management Contracts (72.6) (37.5)
Property Taxes (32.2) (29.7)
Deferred Fuel Over/Under-Recovery, Net (74.3) (13.8)
Change in Other Regulatory Assets (25.1) (4.2)
Change in Other Noncurrent Assets 3.2  (13.7)
Change in Other Noncurrent Liabilities (7.5) (6.2)
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net (38.6) (21.4)
Fuel, Materials and Supplies 3.2  (3.7)
Accounts Payable 120.7  109.8 
Accrued Taxes, Net 44.8  (7.9)
Other Current Assets (16.0) (27.4)
Other Current Liabilities (0.7) (52.2)
Net Cash Flows from Operating Activities 165.7  136.8 
INVESTING ACTIVITIES    
Construction Expenditures (325.2) (270.8)
Change in Advances to Affiliates, Net 232.0  — 
Acquisitions of Generation Facilities (1,359.3) — 
Other Investing Activities 1.0  (2.2)
Net Cash Flows Used for Investing Activities (1,451.5) (273.0)
FINANCING ACTIVITIES    
Capital Contribution from Parent 299.9  0.2 
Issuance of Long-term Debt – Nonaffiliated 793.8  — 
Change in Advances from Affiliates, Net 319.7  207.4 
Retirement of Long-term Debt – Nonaffiliated (125.3) (0.3)
Principal Payments for Finance Lease Obligations (1.6) (1.7)
Dividends Paid on Common Stock —  (70.0)
Other Financing Activities 1.3  0.6 
Net Cash Flows from Financing Activities 1,287.8  136.2 
Net Increase in Cash and Cash Equivalents 2.0  — 
Cash and Cash Equivalents at Beginning of Period 1.8  2.5 
Cash and Cash Equivalents at End of Period $ 3.8  $ 2.5 
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $ 47.3  $ 51.6 
Net Cash Paid (Received) for Income Taxes (4.0) (3.0)
Cash Paid (Received) for Transferable Tax Credits (8.5) (29.6)
Noncash Acquisitions Under Finance Leases 1.8  0.8 
Construction Expenditures Included in Current Liabilities as of June 30, 91.3  61.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
97

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 
June 30,		 Six Months Ended 
June 30,
  2025 2024 2025 2024
  (in millions of KWhs)
Retail:        
Residential 1,365  1,391  2,968  2,900 
Commercial 1,415  1,430  2,660  2,670 
Industrial 1,327  1,414  2,508  2,641 
Miscellaneous 18  18  34  35 
Total Retail 4,125  4,253  8,170  8,246 
Wholesale (a) 1,251  1,340  2,743  2,714 
Total KWhs 5,376  5,593  10,913  10,960 
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.


Summary of Heating and Cooling Degree Days
Three Months Ended 
June 30,		 Six Months Ended 
June 30,
  2025 2024 2025 2024
  (in degree days)
Actual – Heating 9  5  726  560 
Normal – Heating 24  24  714  721 
Actual – Cooling 948  1,042  1,044  1,130 
Normal – Cooling 770  754  816  798 

98

Southwestern Electric Power Company
Reconciliation of 2024 to 2025
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Three Months Ended 
June 30,		 Six Months Ended 
June 30,
2024 Earnings (Loss) Attributable to Common Shareholder
 $ (70.1) $ 138.0 
   
Changes in Revenues:  
Retail Revenues (a) 158.5  173.4 
Off-system Sales (1.6) (1.5)
Transmission Revenues 20.7  20.8 
Other Revenues (3.0) (3.2)
Total Change in Revenues 174.6  189.5 
   
Changes in Expenses and Other:  
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 0.9  (5.4)
Other Operation and Maintenance 12.5  30.1 
Depreciation and Amortization (6.6) (26.1)
Taxes Other Than Income Taxes (3.8) (4.4)
Interest Income (1.9) (3.4)
Allowance for Equity Funds Used During Construction 0.3  0.2 
Non-Service Cost Components of Net Periodic Benefit Cost (0.7) (1.6)
Interest Expense (3.9) (29.7)
Total Change in Expenses and Other (3.2) (40.3)
   
Income Tax Benefit 14.1  (123.7)
Equity Earnings of Unconsolidated Subsidiary —  (0.1)
Net Income Attributable to Noncontrolling Interest 0.2  0.7 
   
2025 Earnings Attributable to Common Shareholder
 $ 115.6  $ 164.1 

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

Second Quarter of 2025 Compared to Second Quarter of 2024

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

•Retail Revenues increased $159 million primarily due to a $160 million revenue refund provision recorded in 2024 associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.
•Transmission Revenues increased $21 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:

•Other Operation and Maintenance expenses decreased $13 million primarily due to the following:
•A $16 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 distribution-related expenses primarily driven by storm costs in Arkansas.
These decreases were partially offset by:
•An $8 million increase in transmission-related expenses primarily due to the June 2025 FERC NOLC order.
99

•Depreciation and Amortization expenses increased $7 million primarily due to:
•A $9 million increase due to a higher depreciable base.
•A $4 million increase due to the amortization of the Storm Recovery Funding securitized assets.
These increases were partially offset by:
•A $4 million decrease due to an increase in regulatory assets related to NOLCs.
•Income Tax Benefit increased $14 million primarily due to the following:
•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 $5 million increase due to an increase in PTCs.
These increases were partially offset by:
•A $36 million decrease due to an increase in pretax book income.

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

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

•Retail Revenues increased $173 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 $43 million increase in rider revenues.
These increases were partially offset by:
•A $31 million decrease in weather-normalized margins in all classes.
•Transmission Revenues increased $21 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 $5 million primarily due to a current year decrease in amortization of under-recovered fuel regulatory assets.
•Other Operation and Maintenance expenses decreased $30 million primarily due to the following:
•A $16 million decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.
•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.
•A $6 million decrease in distribution-related expenses primarily driven by storm costs in Arkansas.
These decreases were partially offset by:
•A $7 million increase in transmission-related expenses primarily due to the June 2025 FERC NOLC order.
•Depreciation and Amortization expenses increased $26 million primarily due to:
•A $17 million increase due to a higher depreciable base.
•An $8 million increase due to the amortization of the Storm Recovery Funding securitized assets.
•Interest Expense increased $30 million primarily due to:
•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 $9 million increase associated with Storm Recovery Funding bonds.
•Income Tax Benefit decreased $124 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 $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 $31 million decrease due to an increase in pretax book income.
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.
100


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
  June 30, June 30,
  2025 2024 2025 2024
REVENUES        
Electric Generation, Transmission and Distribution $ 543.7  $ 546.1  $ 1,066.4  $ 1,055.4 
Sales to AEP Affiliates 24.4  18.7  35.5  30.8 
(Provision for)/Reversal of – Revenue Refund – Nonaffiliated 1.8  (171.4) (4.5) (180.5)
Other Revenues 0.5  2.4  4.1  6.3 
TOTAL REVENUES 570.4  395.8  1,101.5  912.0 
EXPENSES        
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 192.5  193.4  383.4  378.0 
Other Operation 107.1  116.3  204.8  229.2 
Maintenance 50.1  53.4  84.9  90.6 
Depreciation and Amortization 107.8  101.2  206.0  179.9 
Taxes Other Than Income Taxes 29.3  25.5  64.1  59.7 
TOTAL EXPENSES 486.8  489.8  943.2  937.4 
OPERATING INCOME (LOSS) 83.6  (94.0) 158.3  (25.4)
Other Income (Expense):      
Interest Income 2.4  4.3  4.9  8.3 
Allowance for Equity Funds Used During Construction 3.7  3.4  7.0  6.8 
Non-Service Cost Components of Net Periodic Benefit Cost 1.7  2.4  3.4  5.0 
Interest Expense (33.6) (29.7) (72.9) (43.2)
INCOME (LOSS) BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS 57.8  (113.6) 100.7  (48.5)
Income Tax Expense (Benefit) (58.3) (44.2) (64.6) (188.3)
Equity Earnings of Unconsolidated Subsidiary 0.3  0.3  0.6  0.7 
NET INCOME (LOSS) 116.4  (69.1) 165.9  140.5 
Net Income Attributable to Noncontrolling Interest 0.8  1.0  1.8  2.5 
EARNINGS (LOSS) ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $ 115.6  $ (70.1) $ 164.1  $ 138.0 
The common stock of SWEPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
101

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Three Months Ended Six Months Ended
  June 30, June 30,
  2025 2024 2025 2024
Net Income (Loss) $ 116.4  $ (69.1) $ 165.9  $ 140.5 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES        
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $0 and $0 for the Six Months Ended June 30, 2025 and 2024, Respectively
 —  —  (0.1) (0.1)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2025 and 2024, Respectively, and $0 and $0 for the Six Months Ended June 30, 2025 and 2024, Respectively
 —  —  —  (0.1)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) —  —  (0.1) (0.2)
TOTAL COMPREHENSIVE INCOME (LOSS) 116.4  (69.1) 165.8  140.3 
Total Comprehensive Income Attributable to Noncontrolling Interest 0.8  1.0  1.8  2.5 
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $ 115.6  $ (70.1) $ 164.0  $ 137.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
102

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 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 Income 208.1  1.5  209.6 
Other Comprehensive Loss (0.2) (0.2)
TOTAL EQUITY – MARCH 31, 2024 0.1  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, 2024 $ 0.1  $ 1,492.2  $ 2,269.3  $ (3.6) $ 0.3  $ 3,758.3 
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 Income 48.5  1.0  49.5 
Other Comprehensive Loss (0.1) (0.1)
TOTAL EQUITY – MARCH 31, 2025 0.1  1,549.7  2,401.0  2.2  0.4  3,953.4 
Capital Contribution from Parent 450.6  450.6 
Common Stock Dividends – Nonaffiliated         (1.0) (1.0)
Net Income     115.6    0.8  116.4 
TOTAL EQUITY – JUNE 30, 2025 $ 0.1  $ 2,000.3  $ 2,516.6  $ 2.2  $ 0.2  $ 4,519.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
103

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2025 and December 31, 2024
(in millions)
(Unaudited)
  June 30, December 31,
  2025 2024
CURRENT ASSETS    
Cash and Cash Equivalents $ 3.7  $ 1.2 
Restricted Cash
(June 30, 2025 and December 31, 2024 Amounts Include $16.7 and $3.4, Respectively, Related to Storm Recovery Funding)
 16.7  3.4 
Advances to Affiliates 78.7  2.3 
Accounts Receivable:    
Customers 34.5  34.5 
Affiliated Companies 46.6  54.1 
Miscellaneous 8.8  9.2 
Total Accounts Receivable 89.9  97.8 
Fuel 88.0  86.5 
Materials and Supplies
(June 30, 2025 and December 31, 2024 Amounts Include $1.2 and $1.5, Respectively, Related to Sabine)
 85.5  81.4 
Risk Management Assets 70.4  18.1 
Accrued Tax Benefits 57.6  26.0 
Regulatory Asset for Under-Recovered Fuel Costs 109.6  106.6 
Prepayments and Other Current Assets 35.4  14.7 
TOTAL CURRENT ASSETS 635.5  438.0 
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 5,325.1  5,287.5 
Transmission 3,018.0  2,863.8 
Distribution 3,122.2  3,007.1 
Other Property, Plant and Equipment
(June 30, 2025 and December 31, 2024 Amounts Include $129.3 and $166.8, Respectively, Related to Sabine)
 912.7  940.4 
Construction Work in Progress 688.9  627.3 
Total Property, Plant and Equipment 13,066.9  12,726.1 
Accumulated Depreciation and Amortization
(June 30, 2025 and December 31, 2024 Amounts Include $129.3 and $166.8, Respectively, Related to Sabine)
 3,395.0  3,280.0 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 9,671.9  9,446.1 
OTHER NONCURRENT ASSETS    
Regulatory Assets 944.9  921.3 
Securitized Assets
(June 30, 2025 and December 31, 2024 Amounts Include $323.6 and $331.4, Respectively, Related to Storm Recovery Funding)
 323.6  331.4 
Deferred Charges and Other Noncurrent Assets 379.3  358.2 
TOTAL OTHER NONCURRENT ASSETS 1,647.8  1,610.9 
TOTAL ASSETS $ 11,955.2  $ 11,495.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
104

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2025 and December 31, 2024
(Unaudited)
  June 30, December 31,
  2025 2024
  (in millions)
CURRENT LIABILITIES    
Advances from Affiliates $ —  $ 275.0 
Accounts Payable:    
General 281.2  265.5 
Affiliated Companies 92.7  57.1 
Short-term Debt – Nonaffiliated 1.6  5.5 
Long-term Debt Due Within One Year – Nonaffiliated
(June 30, 2025 and December 31, 2024 Amounts Include $19.3 and $22.7, Respectively, Related to Storm Recovery Funding)
 519.3  22.7 
Risk Management Liabilities 3.3  2.3 
Customer Deposits 75.5  75.4 
Accrued Taxes 111.7  48.6 
Accrued Interest 48.0  40.6 
Obligations Under Operating Leases 6.6  8.2 
Provision for Refund 84.6  70.8 
Other Current Liabilities 141.3  159.9 
TOTAL CURRENT LIABILITIES 1,365.8  1,031.6 
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated
(June 30, 2025 and December 31, 2024 Amounts Include $312.6 and $308.7, Respectively, Related to Storm Recovery Funding)
 3,463.7  3,958.1 
Deferred Income Taxes 1,358.9  1,271.3 
Regulatory Liabilities and Deferred Investment Tax Credits 549.4  610.8 
Asset Retirement Obligations 270.2  257.5 
Employee Benefits and Pension Obligations 38.9  46.5 
Obligations Under Operating Leases 132.5  137.5 
Provision for Refund 79.7  107.8 
Storm Reserve 108.7  106.2 
Deferred Credits and Other Noncurrent Liabilities 68.0  62.7 
TOTAL NONCURRENT LIABILITIES 6,070.0  6,558.4 
TOTAL LIABILITIES 7,435.8  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 Capital 2,000.3  1,549.7 
Retained Earnings 2,516.6  2,352.5 
Accumulated Other Comprehensive Income (Loss) 2.2  2.3 
TOTAL COMMON SHAREHOLDER’S EQUITY 4,519.2  3,904.6 
Noncontrolling Interest 0.2  0.4 
TOTAL EQUITY 4,519.4  3,905.0 
TOTAL LIABILITIES AND EQUITY $ 11,955.2  $ 11,495.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
105

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2025 and 2024
(in millions)
(Unaudited)
  Six Months Ended June 30,
  2025 2024
OPERATING ACTIVITIES    
Net Income $ 165.9  $ 140.5 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
Depreciation and Amortization 206.0  179.9 
Deferred Income Taxes 17.9  (136.2)
Allowance for Equity Funds Used During Construction (7.0) (6.8)
Mark-to-Market of Risk Management Contracts (50.9) (31.1)
Pension Contributions to Qualified Plan Trust (8.8) — 
Property Taxes (45.0) (47.4)
Deferred Fuel Over/Under-Recovery, Net 63.5  82.7 
Provision for Refund – Turk Plant —  133.3 
Change in Other Noncurrent Assets (26.7) (12.8)
Change in Other Noncurrent Liabilities (57.1) (40.1)
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net 7.9  (43.0)
Fuel, Materials and Supplies (5.6) 22.1 
Accounts Payable 89.8  60.2 
Accrued Taxes, Net 31.5  19.7 
Provision for Refund – Turk Plant —  26.7 
Other Current Assets (19.7) (26.0)
Other Current Liabilities (4.2) (10.8)
Net Cash Flows from Operating Activities 357.5  310.9 
INVESTING ACTIVITIES    
Construction Expenditures (440.3) (347.7)
Change in Advances to Affiliates, Net (76.4) (0.6)
Other Investing Activities 5.5  0.9 
Net Cash Flows Used for Investing Activities (511.2) (347.4)
FINANCING ACTIVITIES    
Capital Contribution from Parent 450.6  — 
Change in Short-term Debt – Nonaffiliated (3.9) 1.4 
Change in Advances from Affiliates, Net (275.0) 196.7 
Principal Payments for Finance Lease Obligations (2.0) (9.8)
Dividends Paid on Common Stock —  (150.0)
Dividends Paid on Common Stock – Nonaffiliated (2.0) (2.4)
Other Financing Activities 1.8  0.6 
Net Cash Flows from Financing Activities 169.5  36.5 
Net Increase in Cash and Cash Equivalents 15.8  — 
Cash and Cash Equivalents at Beginning of Period 4.6  2.4 
Cash and Cash Equivalents at End of Period $ 20.4  $ 2.4 
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $ 72.2  $ 71.6 
Net Cash Paid (Received) for Income Taxes (28.5) 14.9 
Cash Paid (Received) for Transferable Tax Credits (8.7) (25.4)
Noncash Acquisitions Under Finance Leases 1.8  1.3 
Construction Expenditures Included in Current Liabilities as of June 30, 99.3  93.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 107.
106

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS

The condensed notes to condensed financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise:
Note Registrant Page
Number
Significant Accounting Matters AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
New Accounting Standards AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Comprehensive Income AEP
Rate Matters AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Commitments, Guarantees and Contingencies AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Acquisitions and Dispositions AEP, AEPTCo, PSO
Benefit Plans AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
Business Segments AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Derivatives and Hedging AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
Fair Value Measurements AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
Income Taxes AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Voluntary Severance Program AEP, AEP Texas, AEPTCO, APCo, I&M, OPCo, PSO, SWEPCo
Financing Activities AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Variable Interest Entities AEP
Property, Plant and Equipment AEP, PSO, SWEPCo
Revenue from Contracts with Customers AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
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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 six months ended June 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 June 30,
2025 2024
(in millions, except per share data)
  $/share $/share
Earnings Attributable to AEP Common Shareholders $ 1,225.8    $ 340.3   
Weighted-Average Number of Basic AEP Common Shares Outstanding 534.3  $ 2.29  528.9  $ 0.64 
Weighted-Average Dilutive Effect 2.1  —  1.2  — 
Weighted-Average Number of Diluted AEP Common Shares Outstanding 536.4  $ 2.29  530.1  $ 0.64 

Six Months Ended June 30,
2025 2024
(in millions, except per share data)
  $/share $/share
Earnings Attributable to AEP Common Shareholders $ 2,026.0    $ 1,343.4   
Weighted-Average Number of Basic AEP Common Shares Outstanding 533.8  $ 3.80  527.7  $ 2.55 
Weighted-Average Dilutive Effect 1.7  (0.02) 1.2  (0.01)
Weighted-Average Number of Diluted AEP Common Shares Outstanding 535.5  $ 3.78  528.9  $ 2.54 

There were no antidilutive shares outstanding as of June 30, 2025 and 2024.
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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:
June 30, 2025
AEP AEP Texas APCo SWEPCo
(in millions)
Cash and Cash Equivalents $ 227.3  $ 0.1  $ 6.2  $ 3.7 
Restricted Cash 51.3  13.3  18.2  16.7 
Total Cash, Cash Equivalents and Restricted Cash $ 278.6  $ 13.4  $ 24.4  $ 20.4 

December 31, 2024
AEP AEP Texas APCo SWEPCo
(in millions)
Cash and Cash Equivalents $ 202.9  $ 0.1  $ 3.9  $ 1.2 
Restricted Cash 43.1  23.5  16.2  3.4 
Total Cash, Cash Equivalents and Restricted Cash $ 246.0  $ 23.6  $ 20.1  $ 4.6 

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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

On March 6, 2024, the SEC adopted final rules that 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. A majority of the reporting requirements are applicable to the fiscal year beginning in 2025, with the addition of assurance reporting for GHG emissions starting in 2029 for large accelerated filers. 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. On April 4, 2024, the SEC issued an order staying the final climate disclosure rules pending the completion of judicial review at the Court of Appeals. On March 27, 2025, the SEC announced that it voted to end its defense of the final climate disclosure rules. On April 3, 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. 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.

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.
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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.
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3.  COMPREHENSIVE INCOME

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

Presentation of Comprehensive Income

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

  Cash Flow Hedges Pension  
Three Months Ended June 30, 2025 Commodity Interest Rate and OPEB Total
  (in millions)
Balance in AOCI as of March 31, 2025 $ 123.7  $ 1.2  $ (104.6) $ 20.3 
Change in Fair Value Recognized in AOCI, Net of Tax (36.0) —  —  (36.0)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a) 4.8  —  —  4.8 
Interest Expense (a) —  (1.2) —  (1.2)
Amortization of Prior Service Cost (Credit) —  —  (0.3) (0.3)
Amortization of Actuarial (Gains) Losses —  —  0.6  0.6 
Reclassifications from AOCI, before Income Tax (Expense) Benefit 4.8  (1.2) 0.3  3.9 
Income Tax (Expense) Benefit 1.0  (0.2) —  0.8 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 3.8  (1.0) 0.3  3.1 
Net Current Period Other Comprehensive Income (Loss) (32.2) (1.0) 0.3  (32.9)
Balance in AOCI as of June 30, 2025 $ 91.5  $ 0.2  $ (104.3) $ (12.6)

  Cash Flow Hedges Pension  
Three Months Ended June 30, 2024 Commodity Interest Rate and OPEB Total
  (in millions)
Balance in AOCI as of March 31, 2024 $ 87.2  $ 3.4  $ (152.9) $ (62.3)
Change in Fair Value Recognized in AOCI, Net of Tax 7.0  6.9  —  13.9 
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a) 11.8  —  —  11.8 
Interest Expense (a) —  (1.1) —  (1.1)
Amortization of Prior Service Cost (Credit) —  —  (1.3) (1.3)
Amortization of Actuarial (Gains) Losses —  —  1.2  1.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit 11.8  (1.1) (0.1) 10.6 
Income Tax (Expense) Benefit 2.3  (0.1) —  2.2 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 9.5  (1.0) (0.1) 8.4 
Net Current Period Other Comprehensive Income (Loss) 16.5  5.9  (0.1) 22.3 
Balance in AOCI as of June 30, 2024 $ 103.7  $ 9.3  $ (153.0) $ (40.0)
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  Cash Flow Hedges Pension  
Six Months Ended June 30, 2025 Commodity Interest Rate and OPEB Total
  (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 2.2  (1.0) —  1.2 
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a) (11.7) —  —  (11.7)
Interest Expense (a) —  (2.6) —  (2.6)
Amortization of Prior Service Cost (Credit) —  —  (0.4) (0.4)
Amortization of Actuarial (Gains) Losses —  —  1.1  1.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit (11.7) (2.6) 0.7  (13.6)
Income Tax (Expense) Benefit (2.5) (0.5) 0.1  (2.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (9.2) (2.1) 0.6  (10.7)
Net Current Period Other Comprehensive Income (Loss) (7.0) (3.1) 0.6  (9.5)
Balance in AOCI as of June 30, 2025 $ 91.5  $ 0.2  $ (104.3) $ (12.6)

  Cash Flow Hedges Pension  
Six Months Ended June 30, 2024 Commodity Interest Rate and OPEB Total
  (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 12.5  19.3  —  31.8 
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a) (17.5) —  —  (17.5)
Interest Expense (a) —  (2.3) —  (2.3)
Amortization of Prior Service Cost (Credit) —  —  (2.6) (2.6)
Amortization of Actuarial (Gains) Losses —  —  1.7  1.7 
Reclassifications from AOCI, before Income Tax Expense (17.5) (2.3) (0.9) (20.7)
Income Tax Expense (3.8) (0.4) (0.2) (4.4)
Reclassifications from AOCI, Net of Income Tax Expense (13.7) (1.9) (0.7) (16.3)
Net Current Period Other Comprehensive Income (Loss) (1.2) 17.4  (0.7) 15.5 
Balance in AOCI as of June 30, 2024 $ 103.7  $ 9.3  $ (153.0) $ (40.0)

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

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

As discussed in the 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 Arkansas base rate case filed in March 2025. In July 2023, Texas ALJs issued a PFD that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected the ALJs’ July 2023 PFD. In the open meeting, the commissioners expressed their concerns that the analysis in support of SWEPCo’s decision to retire the Pirkey Plant was not robust enough and that SWEPCo should have re-evaluated the decision following Winter Storm Uri. The treatment of the cost of recovery of the Pirkey Plant is expected to be addressed in a future rate case. As of June 30, 2025, the Texas jurisdictional share of the net book value of the Pirkey Plant was $76 million. To the extent any portion of the Texas jurisdictional share of the net book value of the Pirkey Plant is 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 Certificate of Convenience and Necessity (CCN) with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively.


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The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of June 30, 2025, of generating facilities planned for early retirement:
Plant Net Book Value Accelerated Depreciation Regulatory Asset Cost of Removal
Regulatory Liability		 Projected
Retirement Date		 Current Authorized
Recovery Period		 Annual
Depreciation (a)
(dollars in millions)
Northeastern Plant, Unit 3 $ 79.8  $ 204.7  $ 21.1  (b) 2026 (c) $ 16.7 
Welsh Plant, Units 1 and 3 300.9  192.7  57.7  (d) 2028 (e) (f) 45.9 

(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 June 30, 2025, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $70 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 June 30, 2025, SWEPCo had a net under-recovered fuel balance of $26 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 will seek recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of June 30, 2025, SWEPCo’s share of the net investment in the Pirkey Plant was $204 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 June 30, 2025, SWEPCo had a net under-recovered fuel balance of $26 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. An order is expected in 2025.

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
June 30, December 31,
2025 2024
 Noncurrent Regulatory Assets (in millions)
   
Regulatory Assets Currently Earning a Return    
Welsh Plant, Units 1 and 3 Accelerated Depreciation $ 192.7  $ 168.6 
Pirkey Plant Accelerated Depreciation 132.6  121.3 
Unrecovered Winter Storm Fuel Costs (a) 55.9  70.7 
Storm-Related Costs 53.8  51.0 
AEP Texas House Bill 5247 25.0  — 
Other Regulatory Assets Pending Final Regulatory Approval 26.5  20.7 
Regulatory Assets Currently Not Earning a Return    
Plant Retirement Costs – Asset Retirement Obligation Costs (b) 378.3  357.4 
Storm-Related Costs 310.5  300.8 
2024-2025 Virginia Biennial Under-Earnings 156.5  78.4 
NOLC Costs (c) 88.8  92.8 
Other Regulatory Assets Pending Final Regulatory Approval 107.3  86.3 
Total Regulatory Assets Pending Final Regulatory Approval $ 1,527.9  $ 1,348.0 
(a)Includes $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of June 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)See “NOLCs in Retail Jurisdictions - IRS PLRs” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

AEP Texas
June 30, December 31,
2025 2024
Noncurrent Regulatory Assets (in millions)
Regulatory Assets Currently Earning a Return
Storm-Related Costs $ 41.3  $ 41.3 
AEP Texas House Bill 5247 25.0  — 
Other Regulatory Assets Pending Final Regulatory Approval 1.2  — 
Regulatory Assets Currently Not Earning a Return    
Storm-Related Costs 30.9  13.1 
Deferred Pension and OPEB Costs 21.7  15.6 
Line Inspection Costs 5.8  5.8 
Other Regulatory Assets Pending Final Regulatory Approval 1.4  1.3 
Total Regulatory Assets Pending Final Regulatory Approval $ 127.3  $ 77.1 


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APCo
June 30, December 31,
2025 2024
Noncurrent Regulatory Assets (in millions)
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval $ 1.3  $ 1.1 
Regulatory Assets Currently Not Earning a Return    
Plant Retirement Costs – Asset Retirement Obligation Costs (a) 299.4  282.1 
Storm-Related Costs – West Virginia 163.2  144.2 
2024-2025 Virginia Biennial Under-Earnings 156.5  78.4 
Pension Settlement 17.1  17.8 
Other Regulatory Assets Pending Final Regulatory Approval 20.9  11.9 
Total Regulatory Assets Pending Final Regulatory Approval $ 658.4  $ 535.5 
(a)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.


  I&M
June 30, December 31,
2025 2024
Noncurrent Regulatory Assets (in millions)
   
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval $ 6.7  $ 6.4 
Regulatory Assets Currently Not Earning a Return    
Plant Retirement Costs – Asset Retirement Obligation Costs (a) 76.2  74.0 
Storm-Related Costs – Indiana 24.0  6.3 
NOLC Costs – Indiana (b) —  26.7 
Other Regulatory Assets Pending Final Regulatory Approval 1.9  1.6 
Total Regulatory Assets Pending Final Regulatory Approval $ 108.8  $ 115.0 

(a)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.
(b)See “NOLCs in Retail Jurisdictions - IRS PLRs” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.


  OPCo
June 30, December 31,
2025 2024
Noncurrent Regulatory Assets (in millions)
   
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval $ 0.7  $ 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 $ 0.7  $ 0.5 
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  PSO
June 30, December 31,
2025 2024
Noncurrent Regulatory Assets (in millions)
   
Regulatory Assets Currently Not Earning a Return    
NOLC Costs (a) $ 23.2  $ 16.4 
Storm-Related Costs 21.3  4.9 
Pension Settlement 7.5  7.8 
Other Regulatory Assets Pending Final Regulatory Approval 9.5  1.2 
Total Regulatory Assets Pending Final Regulatory Approval $ 61.5  $ 30.3 

(a)See “NOLCs in Retail Jurisdictions - IRS PLRs” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

SWEPCo
June 30, December 31,
2025 2024
Noncurrent Regulatory Assets (in millions)
   
Regulatory Assets Currently Earning a Return    
Welsh Plant, Units 1 and 3 Accelerated Depreciation $ 192.7  $ 168.6 
Pirkey Plant Accelerated Depreciation 132.6  121.3 
Unrecovered Winter Storm Fuel Costs (a) 55.9  70.7 
Dolet Hills Power Station Accelerated Depreciation (b) 12.0  11.8 
Other Regulatory Assets Pending Final Regulatory Approval 17.1  10.8 
Regulatory Assets Currently Not Earning a Return    
NOLC Costs (c) 65.6  49.6 
Storm-Related Costs - Louisiana, Texas 45.9  39.9 
Other Regulatory Assets Pending Final Regulatory Approval 18.7  18.7 
Total Regulatory Assets Pending Final Regulatory Approval $ 540.5  $ 491.4 

(a)Includes $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of June 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)See “NOLCs in Retail Jurisdictions - IRS PLRs” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

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 June 30, 2025, AEP Texas’ cumulative revenues from transmission and distribution interim base rate increases that are subject to review are estimated to be approximately $43 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 tracking mechanism for qualifying electric utilities to file annual interim rate adjustments for cost recovery of certain transmission and distribution capital expenditures. On June 27, 2025, AEP Texas filed with the PUCT notice of qualification and election to 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 tracking mechanism permits a qualifying electric utility to defer all or a portion of costs associated with its eligible transmission and distribution capital investments, including depreciation expense and carrying costs, as a regulatory asset. The tracking mechanism is available through 2035 and is an alternative to the existing capital tracking mechanisms in Texas. Deferred costs will be recovered through interim rate updates over a period not to exceed 18 months and earn a return until recovered. As a result of the new legislation, AEP Texas deferred approximately $25 million of eligible costs through June 2025 as a regulatory asset. Investments included in the tracking mechanism and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate review before the PUCT. If any of these deferred costs are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

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 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. Staff and intervenor testimony is due in August 2025 and a hearing is scheduled for October 2025.

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.

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In April 2025, the Companies submitted their 2025 ENEC update filing proposing a $72 million annual increase in ENEC rates. In July 2025, WVPSC staff and intervenors filed testimony, and one intervening party recommended a disallowance of approximately $19 million.

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

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 third 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.

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 included 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.

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In April 2025, a hearing was held at the WVPSC to review the Companies’ separate depreciation filing. Also in April 2025, WVPSC staff and intervenors submitted testimony regarding the Companies’ base rate filing recommending combined APCo and WPCo base rate increases ranging from $49 million to $91 million based on proposed ROEs ranging from 9.1% to 9.25%. In May 2025, the combined APCo and WPCo base rate increases range was revised to $49 million to $72 million. These base rate recommendations included significant decreases in rate base for the use of a 13-month average rate base rather than a year-end rate base as proposed by the Companies, and also included various reductions to the Companies’ proposed ongoing levels of depreciation expense and other operation and maintenance expenses. WVPSC staff recommended that the WVPSC approve the Companies’ requested recovery of $118 million of deferred extraordinary storm costs over a five-year period rather than the proposed three-year recovery period, while also recommending that the WVPSC reject the Companies’ proposal of a carrying charge on the storm deferral balance if the recovery is more than three years. WVPSC staff and an intervenor also recommended that the WVPSC deny the ratemaking impact of NOLC and reject the Companies’ request to continue the MRBC surcharge. In May 2025, the Companies filed rebuttal testimony supporting a net $224 million annual increase in base rates. A hearing was held at the WVPSC in June 2025 and an order is expected in the third quarter of 2025.

For the Companies’ first proposed alternative ratemaking framework described above, WVPSC staff and intervenors recommended that the WVPSC: a) consider securitization subject to certain conditions, b) approve the Companies’ proposed major storm deferral accounting for major storm other operation and maintenance expenses against the level embedded in the development of base rates, and c) reject the proposed freeze of OATT revenues in the ENEC. WVPSC staff and intervenors generally recommended that the WVPSC reject the Companies’ second proposed alternative ratemaking framework described above.

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.

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. In July 2025, the WVPSC issued an order stating that a ruling on the Companies’ 2024 MRBC surcharge update filing and all contested issues will be included in the August 2025 order on the Companies’ 2024 West Virginia base case filing. If any refund liabilities are imposed by the WVPSC, it could reduce future net income and cash flows and impact financial condition.

2025 West Virginia Securitization Filing

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

Proposed Securitized Items APCo WPCo Total
(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 (as of February 28, 2023) 174.3  146.8  321.1 
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 (as of June 30, 2024) 115.0  2.9  117.9 
Upfront Financing Costs 10.1  5.7  15.8 
Total $ 1,532.5  $ 863.3  $ 2,395.8 
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The Companies also proposed that the WVPSC consider approving the securitization of additional ENEC under-recovered costs, such as those costs approved in the 2024 ENEC case, as well as additional deferred West Virginia jurisdictional major storm operation and maintenance costs, such as those associated with Hurricane Helene and Winter Storms Blair, Harlow and Jett.

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

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 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.

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through June 30, 2025, AEP’s share of ETT’s cumulative revenues from interim base rate increases that are subject to a prudency review is approximately $1.9 billion. The 2025 ETT base rate case described below could result in a refund to customers if ETT incurs a disallowance of the transmission 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 rates, could reduce future net income and cash flows and impact financial condition.

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 is based upon a proposed 10.6% ROE with a capital structure of 55% debt and 45% common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates. In 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 include 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 includes 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 and the settlement is subject to approval by the PUCT. If any of the costs in the case are not recoverable or revenues collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition.

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

2023 Michigan Power Supply Cost Recovery (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.
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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.

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 since January 2024. In April 2025, KPCo filed an appeal with the Circuit Court in response to the KPSC’s denial to recover PJM transmission costs incurred from January 2024 through the implementation of new rates. A Circuit Court ruling is expected in the second half of 2025.

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

In June 2025, KPCo filed a request with the KPSC for a Certificate of Public Convenience and Necessity (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 plans to request recovery of an estimated $60 million of Mitchell Plant non-ELG capital investments through a future base rate filing.

As of June 30, 2025, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal and including CWIP and inventory, was $535 million.

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

OPCo Rate Matters (Applies to AEP and OPCo)

OVEC Cost Recovery Audits

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

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

In 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. If any costs are disallowed or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

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, in the first quarter of 2025, OPCo recorded a $35 million estimated reduction to its OVEC-related purchased power regulatory asset for deferred net costs that are no longer probable of future recovery.
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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. 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.

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.
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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:

Jurisdiction June 30, 2025 December 31, 2024 Approved Recovery Period Approved Carrying Charge
(in millions)
Arkansas $ 29.6  $ 37.2  6 years (a)
Louisiana 55.9  70.6  (b) (b)
Texas 58.5  72.7  5 years 1.65%
Total $ 144.0  $ 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. APSC staff and intervenor testimony is due in August 2025 and 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.

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 (MPSC) approved a Certificate of Public Convenience and Necessity (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.
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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, which is currently pending and awaiting decision. Additional regulatory proceedings before the PAPUC are expected to resume in 2025 or 2026. In June 2025, the MPSC gave notice that it extended a temporary extension of the construction commencement deadline until the MPSC can further consider the matter at an administrative meeting.

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 has not been canceled and remains necessary to alleviate congestion. PJM continues to evaluate reliability and market efficiency in the area. As of June 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.

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

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

2021 2022 2023 2024 2025 Total
(in millions)
$ 78.3  $ 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. The FERC directed the AEP transmission owning subsidiaries within PJM and SPP to submit compliance filings in August 2025 that will revise 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.

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

AEP AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Total Revenues $ 270.5  $ 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 Operation 53.0  —  14.8  (6.0) 0.1  18.8  10.1 
Income (Loss) Before Income Tax Expense (Benefit) 241.4 214.3 8.0 16.8 (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 Interest 55.2  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. If SWEPCo is unable to recover the remaining regulatory assets associated with retired plants, or refunds of revenues collected under interim rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition.

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.
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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 June 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 June 30, 2025 were as follows:
Company Amount Maturity
  (in millions)  
AEP $ 360.8  July 2025 to July 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 June 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 June 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:
Company Maximum
Potential Loss
(in millions)
AEP $ 38.4 
AEP Texas 8.3 
APCo 5.2 
I&M 3.9 
OPCo 6.5 
PSO 3.5 
SWEPCo 4.3 

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 August 11, 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 August 11, 2025. Reconsideration of the rule will require a new round of notice-and-comment rulemaking. In July 2025, the Federal EPA issued a direct final rule and companion proposed rule that extended 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)

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

In the second quarter of 2025, PSO expanded its generation portfolio by acquiring three electric generation facilities for a total of $1.4 billion. 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 FERC and retail 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 FERC and retail 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 the 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. AEP 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.

The table below summarizes the impact of the acquisitions on PSO’s balance sheet as of June 30, 2025:

Plant Name State Fuel Type Generation Capacity
(MWs)		 Property, Plant and Equipment, Net Operating Lease Assets Asset Retirement Obligations Other Liabilities
(in millions)
Green Country OK Natural Gas 795 $ 818.9  $ —  $ —  $ 91.4  (a)
Pixley KS Solar 189 379.6  8.9  12.4  — 
Flat Ridge IV KS Wind 135 305.3  7.4  3.1  — 
Total 1,119  $ 1,503.8  $ 16.3  $ 15.5  $ 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.

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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 will be used to help finance AEP’s $54 billion capital plan for 2025-2029, announced in November 2024, driven by transmission and distribution infrastructure upgrades and new generation to support anticipated load growth.

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 June 30, 2025 AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Service Cost $ 23.9  $ 2.2  $ 2.2  $ 3.1  $ 2.3  $ 1.6  $ 1.9 
Interest Cost 52.8  4.3  6.3  6.2  4.8  2.5  3.0 
Expected Return on Plan Assets (70.2) (5.5) (9.4) (9.7) (7.4) (3.8) (3.6)
Amortization of Net Actuarial Loss 4.0  0.4  0.5  0.5  0.4  0.1  0.3 
Net Periodic Benefit Cost (Credit) $ 10.5  $ 1.4  $ (0.4) $ 0.1  $ 0.1  $ 0.4  $ 1.6 

Three Months Ended June 30, 2024 AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Service Cost $ 25.6  $ 2.2  $ 2.5  $ 3.3  $ 2.3  $ 1.6  $ 2.1 
Interest Cost 51.9  4.4  6.2  5.9  4.7  2.5  3.1 
Expected Return on Plan Assets (80.2) (6.6) (10.7) (10.6) (8.1) (4.4) (4.4)
Amortization of Net Actuarial Loss 1.1  0.1  0.1  0.1  —  0.1  — 
Net Periodic Benefit Cost (Credit) (a) $ (1.6) $ 0.1  $ (1.9) $ (1.3) $ (1.1) $ (0.2) $ 0.8 

Six Months Ended June 30, 2025 AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Service Cost $ 47.9  $ 4.4  $ 4.6  $ 6.3  $ 4.6  $ 3.0  $ 3.8 
Interest Cost 105.6  8.8  12.5  12.4  9.7  5.2  6.2 
Expected Return on Plan Assets (140.5) (11.1) (18.8) (19.4) (14.7) (7.7) (7.3)
Amortization of Net Actuarial Loss 8.1  0.7  0.9  0.9  0.7  0.3  0.5 
Net Periodic Benefit Cost (Credit) $ 21.1  $ 2.8  $ (0.8) $ 0.2  $ 0.3  $ 0.8  $ 3.2 

Six Months Ended June 30, 2024 AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Service Cost $ 51.2  $ 4.4  $ 4.9  $ 6.6  $ 4.7  $ 3.1  $ 4.0 
Interest Cost 103.8  8.7  12.4  11.9  9.4  5.0  6.2 
Expected Return on Plan Assets (160.4) (13.0) (21.4) (21.4) (16.3) (8.7) (8.8)
Amortization of Net Actuarial Loss 2.2  0.2  0.2  0.2  0.1  0.1  0.1 
Net Periodic Benefit Cost (Credit) (a) $ (3.2) $ 0.3  $ (3.9) $ (2.7) $ (2.1) $ (0.5) $ 1.5 

(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.
135

OPEB

Three Months Ended June 30, 2025 AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Service Cost $ 1.0  $ 0.1  $ 0.2  $ 0.2  $ 0.1  $ 0.1  $ — 
Interest Cost 8.6  0.7  1.3  0.9  0.9  0.5  0.6 
Expected Return on Plan Assets (28.3) (2.4) (4.1) (3.3) (3.0) (1.5) (1.9)
Amortization of Prior Service Credit (0.6) (0.1) (0.1) (0.1) —  (0.1) (0.1)
Amortization of Net Actuarial Gain (0.3) —  (0.1) —  —  —  — 
Net Periodic Benefit Credit $ (19.6) $ (1.7) $ (2.8) $ (2.3) $ (2.0) $ (1.0) $ (1.4)

Three Months Ended June 30, 2024 AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Service Cost $ 1.1  $ 0.1  $ 0.1  $ 0.2  $ 0.1  $ —  $ 0.1 
Interest Cost 10.6  0.8  1.6  1.2  1.0  0.6  0.6 
Expected Return on Plan Assets (27.9) (2.2) (4.1) (3.3) (2.9) (1.6) (1.8)
Amortization of Prior Service Credit (3.2) (0.2) (0.4) (0.5) (0.3) (0.2) (0.2)
Amortization of Net Actuarial Loss 0.7  —  0.1  0.1  0.1  0.1  — 
Net Periodic Benefit Credit (a) $ (18.7) $ (1.5) $ (2.7) $ (2.3) $ (2.0) $ (1.1) $ (1.3)

Six Months Ended June 30, 2025 AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Service Cost $ 1.8  $ 0.2  $ 0.3  $ 0.3  $ 0.2  $ 0.1  $ 0.1 
Interest Cost 17.2  1.3  2.7  1.9  1.7  0.9  1.1 
Expected Return on Plan Assets (56.5) (4.7) (8.2) (6.7) (5.9) (3.0) (3.8)
Amortization of Prior Service Credit (1.2) (0.1) (0.2) (0.2) (0.1) (0.1) (0.1)
Amortization of Net Actuarial Gain (0.6) —  (0.2) —  —  —  — 
Net Periodic Benefit Credit $ (39.3) $ (3.3) $ (5.6) $ (4.7) $ (4.1) $ (2.1) $ (2.7)

Six Months Ended June 30, 2024 AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Service Cost $ 2.2  $ 0.2  $ 0.2  $ 0.3  $ 0.2  $ 0.1  $ 0.2 
Interest Cost 21.1  1.6  3.3  2.4  2.1  1.1  1.3 
Expected Return on Plan Assets (55.7) (4.5) (8.1) (6.7) (5.9) (3.0) (3.7)
Amortization of Prior Service Credit (6.4) (0.5) (0.9) (0.9) (0.6) (0.4) (0.5)
Amortization of Net Actuarial Loss 1.5  0.1  0.2  0.2  0.2  0.1  0.1 
Net Periodic Benefit Credit (a) $ (37.3) $ (3.1) $ (5.3) $ (4.7) $ (4.0) $ (2.1) $ (2.6)

(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.


136

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

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

Company Qualified Pension Plan
(in millions)
AEP $ 94.7 
AEP Texas 12.0 
APCo 0.4 
I&M 2.1 
PSO 1.4 
SWEPCo 8.8 
137

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.

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.

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.







138

The tables below represent AEP’s reportable segment income statement information for the three and six months ended June 30, 2025 and 2024 and reportable segment balance sheet information as of June 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 June 30, 2025
VIU T&D AEPTHCo G&M Total Reportable Segments Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:
External Customers $ 2,934.5  $ 1,442.6  $ 155.1  $ 551.0  $ 5,083.2  $ 3.7  $ —  $ 5,086.9 
Other Operating Segments 80.7  7.6  601.5  15.2  705.0  25.9  (730.9) (b) — 
Total Revenues 3,015.2  1,450.2  756.6  566.2  5,788.2  29.6  (730.9) 5,086.9 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 920.5  203.7  —  493.4  1,617.6  —  (76.2) 1,541.4 
Other Operation and Maintenance 981.8  541.1  45.0  (0.3) 1,567.6  20.5  (659.8) 928.3 
Depreciation and Amortization 531.3  201.5  121.1  4.3  858.2  (5.0) (0.1) 853.1 
Taxes Other Than Income Taxes 122.9  159.3  77.2  0.3  359.7  0.1  5.2  365.0 
Allowance for Equity Funds Used During Construction 16.0  19.6  21.5  —  57.1  —  —  57.1 
Interest Expense 201.0  100.0  58.7  2.0  361.7  151.1  (23.3) 489.5 
Income Tax Expense (Benefit) (136.4) 50.9  (139.3) 18.2  (206.6) (44.3) —  (250.9)
Equity Earnings (Loss) of Unconsolidated Subsidiaries 0.3  0.1  22.5  —  22.9  (2.3) —  20.6 
Other Segment Items (c) (22.3) (10.5) 59.5  (13.8) 12.9  (23.8) 23.3  12.4 
Earnings (Loss) Attributable to AEP Common Shareholders $ 432.7  $ 223.9  $ 578.4  $ 62.1  $ 1,297.1  $ (71.3) $ —  $ 1,225.8 
Gross Property Additions $ 2,232.6  $ 663.7  $ 383.6  $ 2.8  $ 3,282.7  $ 5.8  $ (9.2) $ 3,279.3 

Three Months Ended June 30, 2024
VIU T&D AEPTHCo G&M Total Reportable Segments Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:
External Customers $ 2,572.0  $ 1,428.8  $ 108.7  $ 442.5  $ 4,552.0  $ 27.2  $ —  $ 4,579.2 
Other Operating Segments 47.0  7.1  381.2  25.0  460.3  30.5  (490.8) (b) — 
Total Revenues 2,619.0  1,435.9  489.9  467.5  5,012.3  57.7  (490.8) 4,579.2 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 870.8  210.5  —  364.8  1,446.1  —  (77.6) 1,368.5 
Other Operation and Maintenance 953.2  520.7  45.7  42.4  1,562.0  24.9  (418.1) 1,168.8 
Asset Impairments and Other Related Charges 13.4  52.9  —  76.2  142.5  —  —  142.5 
Depreciation and Amortization 486.2  226.9  108.9  5.1  827.1  (5.2) —  821.9 
Taxes Other Than Income Taxes 132.9  178.0  77.2  0.5  388.6  0.1  4.9  393.6 
Allowance for Equity Funds Used During Construction 12.8  19.8  22.6  —  55.2  —  —  55.2 
Interest Expense 190.2  95.8  53.3  4.9  344.2  155.3  (33.9) 465.6 
Income Tax Expense (Benefit) (53.7) 35.4  57.0  (6.3) 32.4  (25.7) —  6.7 
Equity Earnings (Loss) of Unconsolidated Subsidiaries 0.3  (0.7) 26.9  —  26.5  (1.3) —  25.2 
Other Segment Items (c) (26.6) (12.0) (3.4) (15.3) (57.3) (24.9) 33.9  (48.3)
Earnings (Loss) Attributable to AEP Common Shareholders $ 65.7  $ 146.8  $ 200.7  $ (4.8) $ 408.4  $ (68.1) $ —  $ 340.3 
Gross Property Additions $ 679.1  $ 548.8  $ 325.0  $ 10.1  $ 1,563.0  $ 6.4  $ (12.8) $ 1,556.6 


139

Six Months Ended June 30, 2025
VIU T&D AEPTHCo G&M Total Reportable Segments Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:
External Customers $ 6,020.0  $ 2,958.1  $ 271.0  $ 1,281.6  $ 10,530.7  $ 19.6  $ —  $ 10,550.3 
Other Operating Segments 133.0  18.6  1,027.7  31.5  1,210.8  54.6  (1,265.4) (b) — 
Total Revenues 6,153.0  2,976.7  1,298.7  1,313.1  11,741.5  74.2  (1,265.4) 10,550.3 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 1,995.9  466.5  —  1,075.9  3,538.3  —  (144.0) 3,394.3 
Other Operation and Maintenance 1,865.2  1,118.2  82.4  30.1  3,095.9  36.3  (1,133.0) 1,999.2 
Depreciation and Amortization 1,046.5  404.4  237.3  8.4  1,696.6  (10.1) —  1,686.5 
Taxes Other Than Income Taxes 256.5  364.5  152.8  1.0  774.8  0.6  11.6  787.0 
Allowance for Equity Funds Used During Construction 32.4  38.1  43.9  —  114.4  —  —  114.4 
Interest Expense 401.7  211.6  115.6  3.9  732.8  298.1  (46.5) 984.4 
Income Tax Expense (Benefit) (91.6) 84.7  (72.4) 54.5  (24.8) (100.6) —  (125.4)
Equity Earnings of Unconsolidated Subsidiaries 0.6  1.4  45.7  —  47.7  11.1  —  58.8 
Other Segment Items (c) (45.0) (22.2) 59.6  (25.2) (32.8) (42.2) 46.5  (28.5)
Earnings (Loss) Attributable to AEP Common Shareholders $ 756.8  $ 388.5  $ 813.0  $ 164.5  $ 2,122.8  $ (96.8) $ —  $ 2,026.0 
Gross Property Additions $ 3,153.2  $ 1,367.7  $ 813.9  $ 6.7  $ 5,341.5  $ 35.8  $ 2.2  $ 5,379.5 

Six Months Ended June 30, 2024
VIU T&D AEPTHCo G&M Total Reportable Segments Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:
External Customers $ 5,473.2  $ 2,912.0  $ 219.2  $ 958.4  $ 9,562.8  $ 42.1  $ —  $ 9,604.9 
Other Operating Segments 93.7  14.1  768.0  72.6  948.4  68.4  (1,016.8) (b) — 
Total Revenues 5,566.9  2,926.1  987.2  1,031.0  10,511.2  110.5  (1,016.8) 9,604.9 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 1,869.9  515.8  —  737.4  3,123.1  —  (178.8) 2,944.3 
Other Operation and Maintenance 1,838.5  1,039.9  82.8  73.9  3,035.1  61.0  (847.5) 2,248.6 
Asset Impairments and Other Related Charges 13.4  52.9  —  76.2  142.5  —  —  142.5 
Depreciation and Amortization 939.8  449.4  217.0  13.3  1,619.5  (10.5) —  1,609.0 
Taxes Other Than Income Taxes 272.6  368.8  152.2  0.7  794.3  0.2  9.5  804.0 
Allowance for Equity Funds Used During Construction 24.5  33.9  40.4  —  98.8  —  —  98.8 
Interest Expense 347.4  192.0  110.2  10.9  660.5  311.1  (70.4) 901.2 
Income Tax Expense (Benefit) (259.9) 66.9  111.3  18.8  (62.9) (72.3) —  (135.2)
Equity Earnings (Loss) of Unconsolidated Subsidiaries 0.7  (0.8) 49.6  0.9  50.4  (0.7) —  49.7 
Other Segment Items (c) (56.1) (23.6) (5.7) (32.1) (117.5) (57.3) 70.4  (104.4)
Earnings (Loss) Attributable to AEP Common Shareholders $ 626.5  $ 297.1  $ 409.4  $ 132.8  $ 1,465.8  $ (122.4) $ —  $ 1,343.4 
Gross Property Additions $ 1,480.9  $ 1,121.1  $ 694.6  $ 20.0  $ 3,316.6  $ 9.5  $ (7.8) $ 3,318.3 

140

June 30, 2025
VIU T&D AEPTHCo G&M Total Reportable Segments Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Total Assets $ 57,909.4  $ 27,526.9  $ 18,705.5  $ 1,896.9  $ 106,038.7  $ 5,316.2  (d) $ (3,576.4) (e) $ 107,778.5 
Investments in Equity Method Investees $ 9.0  $ 3.5  $ 1,036.8  $ —  $ 1,049.3  $ 64.9  $ —  $ 1,114.2 

December 31, 2024
VIU T&D AEPTHCo G&M Total Reportable Segments Corporate and Other (a) Reconciling Adjustments Consolidated
(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.
141

The tables below present AEPTCo’s reportable segment income statement information for the three and six months ended June 30, 2025 and 2024 and reportable segment balance sheet information as of June 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 June 30, 2025
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
 $ 144.6  $ —  $ —  $ 144.6 
Sales to AEP Affiliates
 597.1  —  —  597.1 
Other Revenues
 0.1  —  —  0.1 
Total Revenues 741.8  —  —  741.8 
Other Operation and Maintenance 42.2  —  —  42.2 
Depreciation and Amortization
118.9  —  —  118.9 
Taxes Other Than Income Taxes 75.8  —  —  75.8 
Interest Income
 0.9  84.0  (83.5) (a) 1.4 
Allowance for Equity Funds Used During Construction 21.5  —  —  21.5 
Interest Expense 77.5  62.6  (83.5) (a) 56.6 
Income Tax Expense (Benefit) (156.0) 10.7  —  (145.3)
Other Segment Items (b) —  60.7  —  60.7 
Earnings (Loss) Attributable to AEPTCo Common Shareholders $ 605.8  $ (50.0) (c) $ —  $ 555.8 
Gross Property Additions $ 365.1  $ —  $ —  $ 365.1 

Three Months Ended June 30, 2024
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
 $ 97.0  $ —  $ —  $ 97.0 
Sales to AEP Affiliates
 377.8  —  —  377.8 
Other Revenues
 0.4  —  —  0.4 
Total Revenues 475.2  —  —  475.2 
Other Operation and Maintenance 44.9  0.1  —  45.0 
Depreciation and Amortization
106.7  —  —  106.7 
Taxes Other Than Income Taxes 75.5  —  —  75.5 
Interest Income
 3.5  61.7  (60.9) (a) 4.3 
Allowance for Equity Funds Used During Construction 22.5  —  —  22.5 
Interest Expense 51.4  60.9  (60.9) (a) 51.4 
Income Tax Expense 47.5  0.2  —  47.7 
Earnings Attributable to AEPTCo Common Shareholders $ 175.2  $ 0.5  (c) $ —  $ 175.7 
Gross Property Additions $ 321.3  $ —  $ —  $ 321.3 

142

Six Months Ended June 30, 2025
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
 $ 248.9  $ —  $ —  $ 248.9 
Sales to AEP Affiliates
 1,019.9  —  —  1,019.9 
Other Revenues
 0.1  —  —  0.1 
Total Revenues 1,268.9  —  —  1,268.9 
Other Operation and Maintenance 76.4  0.2  —  76.6 
Depreciation and Amortization
233.0  —  —  233.0 
Taxes Other Than Income Taxes 149.9  —  —  149.9 
Interest Income
 1.0  173.3  (172.5) (a) 1.8 
Allowance for Equity Funds Used During Construction 43.9  —  —  43.9 
Interest Expense 161.5  122.6  (172.5) (a) 111.6 
Income Tax Expense (Benefit) (95.2) 10.7  —  (84.5)
Other Segment Items (b) —  60.7  —  60.7 
Earnings (Loss) Attributable to AEPTCo Common Shareholders $ 788.2  $ (20.9) (c) $ —  $ 767.3 
Gross Property Additions $ 786.9  $ —  $ —  $ 786.9 

Six Months Ended June 30, 2024
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
 $ 194.0  $ —  $ —  $ 194.0 
Sales to AEP Affiliates
 761.2  —  —  761.2 
Other Revenues
 2.8  —  —  2.8 
Total Revenues 958.0  —  —  958.0 
Other Operation and Maintenance 78.6  1.6  —  80.2 
Depreciation and Amortization
212.6  —  —  212.6 
Taxes Other Than Income Taxes 148.9  —  —  148.9 
Interest Income
 4.5  118.8  (117.1) (a) 6.2 
Allowance for Equity Funds Used During Construction 40.4  —  —  40.4 
Interest Expense 106.1  117.2  (117.1) (a) 106.2 
Income Tax Expense 99.8  —  —  99.8 
Earnings Attributable to AEPTCo Common Shareholders $ 356.9  $ —  (c) $ —  $ 356.9 
Gross Property Additions $ 657.8  $ —  $ —  $ 657.8 

June 30, 2025
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Total Assets $ 17,080.1  $ 6,241.3  (d) $ (6,288.6) (e) $ 17,032.8 

December 31, 2024
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
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.
143

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
June 30, 2025 December 31, 2024
Primary Risk
Exposure		 AEP AEP Texas APCo I&M OPCo PSO SWEPCo AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Commodity:          
Power (MWhs) 373.7  —  51.9  16.0  1.9  17.8  14.5  282.4  —  23.6  7.7  2.0  5.0  4.6 
Natural Gas (MMBtus) 174.3  —  45.3  —  —  54.1  22.3  152.8  —  42.2  —  —  46.2  15.4 
Heating Oil and Gasoline (Gallons) 6.6  1.9  0.8  1.2  1.0  0.6  0.8  7.9  2.0  0.9  2.0  1.1  0.7  0.9 
Interest Rate (USD) $ 49.3  $ —  $ —  $ —  $ —  $ —  $ —  $ 59.3  $ —  $ —  $ —  $ —  $ —  $ — 
Interest Rate on Long-term Debt (USD) $ 950.0  $ —  $ —  $ —  $ —  $ —  $ —  $ 950.0  $ —  $ —  $ —  $ —  $ —  $ — 
144

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 $95 million and $87 million as of June 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 June 30, 2025 and December 31, 2024. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $15 million and $3 million as of June 30, 2025 and December 31, 2024, respectively. I&M netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $10 million and $600 thousand as of June 30, 2025 and December 31, 2024, respectively. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was not material for the other Registrant Subsidiaries as of June 30, 2025 and December 31, 2024.
145

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.

June 30, 2025
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
Assets: (in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity $ 748.4  $ —  $ 111.4  $ 29.4  $ —  $ 100.0  $ 71.3 
Hedging Contracts - Commodity 67.0  —  —  —  —  —  — 
Total Current Risk Management Assets 815.4  —  111.4  29.4  —  100.0  71.3 
Long-term Risk Management Assets
Risk Management Contracts - Commodity 527.6  —  2.1  3.5  —  0.1  0.4 
Hedging Contracts - Commodity 79.8  —  —  —  —  —  — 
Total Long-term Risk Management Assets 607.4  —  2.1  3.5  —  0.1  0.4 
Total Assets $ 1,422.8  $ —  $ 113.5  $ 32.9  $ —  $ 100.1  $ 71.7 
Liabilities:
Current Risk Management Liabilities
Risk Management Contracts - Commodity $ 390.3  $ 0.2  $ 5.2  $ 27.5  $ 6.0  $ 8.8  $ 4.2 
Hedging Contracts - Commodity 20.1  —  —  —  —  —  — 
Hedging Contracts - Interest Rate 26.9  —  —  —  —  —  — 
Total Current Risk Management Liabilities 437.3  0.2  5.2  27.5  6.0  8.8  4.2 
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity 443.8  —  1.2  4.1  41.8  2.6  0.9 
Hedging Contracts - Commodity 10.8  —  —  —  —  —  — 
Hedging Contracts - Interest Rate 21.0  —  —  —  —  —  — 
Total Long-term Risk Management Liabilities 475.6  —  1.2  4.1  41.8  2.6  0.9 
Total Liabilities $ 912.9  $ 0.2  $ 6.4  $ 31.6  $ 47.8  $ 11.4  $ 5.1 
Total MTM Derivative Contract Net Assets (Liabilities) Recognized $ 509.9  $ (0.2) $ 107.1  $ 1.3  $ (47.8) $ 88.7  $ 66.6 
146

December 31, 2024
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
Assets: (in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity $ 425.0  $ —  $ 40.2  $ 28.5  $ —  $ 22.3  $ 19.1 
Hedging Contracts - Commodity 54.1  —  —  —  —  —  — 
Total Current Risk Management Assets 479.1  —  40.2  28.5  —  22.3  19.1 
Long-term Risk Management Assets
Risk Management Contracts - Commodity 475.4  —  2.0  1.2  —  1.6  — 
Hedging Contracts - Commodity 84.6  —  —  —  —  —  — 
Total Long-term Risk Management Assets 560.0  —  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 - Commodity 11.3  —  —  —  —  —  — 
Hedging Contracts - Interest Rate 36.3  —  —  —  —  —  — 
Total Current Risk Management Liabilities 351.7  0.3  6.6  10.5  7.5  7.6  3.4 
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity 390.7  —  0.8  2.1  40.2  0.2  — 
Hedging Contracts - Commodity 2.7  —  —  —  —  —  — 
Hedging Contracts - Interest Rate 35.3  —  —  —  —  —  — 
Total Long-term Risk Management Liabilities 428.7  —  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 



147

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.

June 30, 2025
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
Assets: (in millions)
Current Risk Management Assets
Gross Amounts Recognized $ 815.4  $ —  $ 111.4  $ 29.4  $ —  $ 100.0  $ 71.3 
Gross Amounts Offset (346.1) —  (2.7) (17.1) —  (3.1) (0.9)
Net Amounts Presented 469.3  —  108.7  12.3  —  96.9  70.4 
Long-term Risk Management Assets
Gross Amounts Recognized 607.4  —  2.1  3.5  —  0.1  0.4 
Gross Amounts Offset (348.5) —  (0.9) (3.5) —  (0.1) (0.4)
Net Amounts Presented 258.9  —  1.2  —  —  —  — 
Total Assets $ 728.2  $ —  $ 109.9  $ 12.3  $ —  $ 96.9  $ 70.4 
Liabilities:
Current Risk Management Liabilities
Gross Amounts Recognized $ 437.3  $ 0.2  $ 5.2  $ 27.5  $ 6.0  $ 8.8  $ 4.2 
Gross Amounts Offset (331.2) (0.2) (3.2) (26.6) (0.1) (3.2) (0.9)
Net Amounts Presented 106.1  —  2.0  0.9  5.9  5.6  3.3 
Long-term Risk Management Liabilities
Gross Amounts Recognized 475.6  —  1.2  4.1  41.8  2.6  0.9 
Gross Amounts Offset (284.0) —  (0.9) (3.8) —  (0.1) (0.4)
Net Amounts Presented 191.6  —  0.3  0.3  41.8  2.5  0.5 
Total Liabilities $ 297.7  $ —  $ 2.3  $ 1.2  $ 47.7  $ 8.1  $ 3.8 
Total MTM Derivative Contract Net Assets (Liabilities) $ 430.5  $ —  $ 107.6  $ 11.1  $ (47.7) $ 88.8  $ 66.6 

148

December 31, 2024
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
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 Presented 210.4  —  35.7  18.4  —  20.6  18.1 
Long-term Risk Management Assets
Gross Amounts Recognized 560.0  —  2.0  1.2  —  1.6  — 
Gross Amounts Offset (270.9) —  (0.6) (1.2) —  (0.2) — 
Net Amounts Presented 289.1  —  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 Presented 100.0  —  2.0  0.3  7.3  5.8  2.3 
Long-term Risk Management Liabilities
Gross Amounts Recognized 428.7  —  0.8  2.1  40.2  0.2  — 
Gross Amounts Offset (204.3) —  (0.6) (1.7) —  (0.2) — 
Net Amounts Presented 224.4  —  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 

149

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 June 30, 2025
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ 12.3  $ —  $ —  $ —  $ —  $ —  $ — 
Generation & Marketing Revenues (13.0) —  —  —  —  —  — 
Electric Generation, Transmission and Distribution Revenues —  —  0.2  12.2  —  —  — 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 0.7  —  0.9  (0.1) —  —  — 
Other Operation (0.1) (0.1) —  —  —  —  — 
Maintenance (0.3) (0.1) —  —  —  —  (0.1)
Regulatory Assets (a) (6.1) 0.1  (0.1) (1.0) 3.4  (5.6) (3.0)
Regulatory Liabilities (a) 77.2  —  2.5  4.3  2.6  28.4  41.5 
Total Gain (Loss) on Risk Management Contracts $ 70.7  $ (0.1) $ 3.5  $ 15.4  $ 6.0  $ 22.8  $ 38.4 

Three Months Ended June 30, 2024
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ 4.3  $ —  $ —  $ —  $ —  $ —  $ — 
Generation & Marketing Revenues (53.0) —  —  —  —  —  — 
Electric Generation, Transmission and Distribution Revenues —  —  —  4.3  —  —  — 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 0.7  —  0.7  0.1  —  —  — 
Other Operation 0.3  0.1  —  0.1  —  —  — 
Maintenance 0.5  0.1  0.1  0.1  0.1  —  0.1 
Regulatory Assets (a) 31.7  0.1  15.2  4.6  (3.1) 8.9  0.2 
Regulatory Liabilities (a) 92.5  (0.2) 12.6  7.1  —  33.8  34.6 
Total Gain (Loss) on Risk Management Contracts $ 77.0  $ 0.1  $ 28.6  $ 16.3  $ (3.0) $ 42.7  $ 34.9 

150

Six Months Ended June 30, 2025
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ (20.2) $ —  $ —  $ —  $ —  $ —  $ — 
Generation & Marketing Revenues 60.2  —  —  —  —  —  — 
Electric Generation, Transmission and Distribution Revenues —  —  0.3  (20.5) —  —  — 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 3.8  —  3.8  —  —  —  — 
Other Operation (0.2) (0.1) —  —  —  —  — 
Maintenance (0.4) (0.1) —  —  —  —  (0.1)
Regulatory Assets (a) (4.5) 0.2  —  (1.0) (0.3) (1.8) (1.9)
Regulatory Liabilities (a) 230.1  —  59.5  14.8  5.8  67.0  70.7 
Total Gain (Loss) on Risk Management Contracts $ 268.8  $ —  $ 63.6  $ (6.7) $ 5.5  $ 65.2  $ 68.7 
Six Months Ended June 30, 2024
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ (21.4) $ —  $ —  $ —  $ —  $ —  $ — 
Generation & Marketing Revenues (97.7) —  —  —  —  —  — 
Electric Generation, Transmission and Distribution Revenues —  —  0.1  (21.5) —  —  — 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 1.7  —  1.6  0.1  —  —  — 
Other Operation 0.3  0.1  —  0.1  —  —  — 
Maintenance 0.6  0.1  0.1  0.1  0.1  —  0.1 
Regulatory Assets (a) 45.2  0.3  15.1  3.0  5.5  7.7  5.1 
Regulatory Liabilities (a) 145.2  —  25.7  9.3  —  52.1  49.6 
Total Gain (Loss) on Risk Management Contracts $ 73.9  $ 0.5  $ 42.6  $ (8.9) $ 5.6  $ 59.8  $ 54.8 

(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.”
151

Accounting for Fair Value Hedging Strategies (Applies to AEP)

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

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

The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:
Carrying Amount of the Hedged Liabilities Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
June 30, 2025 December 31, 2024 June 30, 2025 December 31, 2024
(in millions)
Long-term Debt (a) (b) $ (919.1) $ (898.6) $ 29.5  $ 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 $(18) million and $(22) million as of June 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 June 30, Six Months Ended June 30,
2025 2024 2025 2024
(in millions)
Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a) $ 20.5  $ 18.2  $ 23.6  $ 1.8 
Fair Value Portion of Long-term Debt (a) (20.5) (18.2) (23.6) (1.8)

(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 six months ended June 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 six months ended June 30, 2025, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives. During the three and six months ended June 30, 2024, AEP and AEP Texas 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.
152

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
June 30, 2025 December 31, 2024
Portion Expected to Portion Expected to
AOCI be Reclassed to AOCI be Reclassed to
Gain (Loss) Net Income During Gain (Loss) Net Income During
Net of Tax the Next Twelve Months Net of Tax the Next Twelve Months
Commodity Interest Rate Commodity Interest Rate Commodity Interest Rate Commodity Interest Rate
(in millions)
AEP $ 91.5  $ 0.2  $ 37.1  $ 0.8  $ 98.5  $ 3.3  $ 33.9  $ 2.8 
AEP Texas —  5.9  —  0.7  —  6.3  —  0.7 
APCo —  4.7  —  0.8  —  5.1  —  0.8 
I&M —  (4.9) —  (0.4) —  (5.1) —  (0.4)
PSO —  2.4  —  0.2  —  3.6  —  0.2 
SWEPCo —  0.9  —  0.3  —  1.0  —  0.3 

As of June 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 June 30, 2025 and December 31, 2024. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of June 30, 2025 and December 31, 2024.

153

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 $48 million and $72 million and no cash collateral posted as of June 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 June 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 $153 million and $164 million and no cash collateral posted as of June 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, $8 million and $2 million, respectively, and no cash collateral posted as of June 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 June 30, 2025 and December 31, 2024.
154

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.


155

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:
June 30, 2025 December 31, 2024
Company Book Value Fair Value Book Value Fair Value
(in millions)
AEP $ 44,525.5  $ 41,138.3  $ 42,642.8  $ 38,964.7 
AEP Texas 6,832.3  6,303.0  6,441.6  5,831.4 
AEPTCo 6,098.5  5,346.8  5,768.1  4,853.1 
APCo 5,772.0  5,577.2  5,660.3  5,346.0 
I&M 3,510.9  3,250.4  3,494.3  3,153.8 
OPCo 3,717.1  3,138.3  3,715.7  3,203.4 
PSO 3,524.0  3,310.8  2,855.6  2,562.1 
SWEPCo 3,983.0  3,593.4  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:
June 30, 2025
Gross Gross
Unrealized Unrealized Fair
Other Temporary Investments and Restricted Cash Cost Gains Losses Value
(in millions)
Restricted Cash (a) $ 51.3  $ —  $ —  $ 51.3 
Other Cash Deposits 16.1  —  —  16.1 
Fixed Income Securities – Mutual Funds (b) 159.8  —  (3.0) 156.8 
Equity Securities – Mutual Funds 14.0  25.1  —  39.1 
Total Other Temporary Investments and Restricted Cash $ 241.2  $ 25.1  $ (3.0) $ 263.3 
December 31, 2024
Gross Gross
Unrealized Unrealized Fair
Other Temporary Investments and Restricted Cash Cost Gains Losses Value
(in millions)
Restricted Cash (a) $ 43.1  $ —  $ —  $ 43.1 
Other Cash Deposits 13.9  —  —  13.9 
Fixed Income Securities – Mutual Funds (b) 167.2  —  (5.3) 161.9 
Equity Securities – Mutual Funds 12.7  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.
156

The following table provides the activity for fixed income and equity securities within Other Temporary Investments:
  Three Months Ended June 30, Six Months Ended June 30,
  2025 2024 2025 2024
(in millions)
Proceeds from Investment Sales $ 6.6  $ —  $ 16.6  $ 3.0 
Purchases of Investments 5.0  1.5  6.5  3.0 
Gross Realized Gains on Investment Sales 0.2  —  4.2  0.3 
Gross Realized Losses on Investment Sales 0.3  —  0.5  0.2 

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:
  June 30, 2025 December 31, 2024
Gross Gross Other-Than- Gross Gross Other-Than-
Fair Unrealized Unrealized Temporary Fair Unrealized Unrealized Temporary
Value Gains Losses Impairments Value Gains Losses Impairments
(in millions)
Cash and Cash Equivalents $ 28.1  $ —  $ —  $ —  $ 23.3  $ —  $ —  $ — 
Fixed Income Securities:
United States Government 1,298.6  3.3  (9.0) (16.9) 1,322.8  8.2  (5.3) (20.2)
Corporate Debt 274.8  20.5  (1.0) (7.1) 211.3  0.7  (9.8) (5.8)
State and Local Government —  —  —  —  —  —  —  — 
Subtotal Fixed Income Securities 1,573.4  23.8  (10.0) (24.0) 1,534.1  8.9  (15.1) (26.0)
Equity Securities - Domestic 3,008.2  2,444.9  (0.5) —  2,837.7  2,288.9  (0.4) — 
Spent Nuclear Fuel and Decommissioning Trusts $ 4,609.7  $ 2,468.7  $ (10.5) $ (24.0) $ 4,395.1  $ 2,297.8  $ (15.5) $ (26.0)

157

The following table provides the securities activity within the decommissioning and SNF trusts:
Three Months Ended June 30, Six Months Ended June 30,
  2025 2024 2025 2024
  (in millions)
Proceeds from Investment Sales $ 717.9  $ 584.6  $ 1,294.4  $ 1,154.1 
Purchases of Investments 728.8  598.6  1,330.0  1,187.1 
Gross Realized Gains on Investment Sales 2.4  4.9  4.3  10.3 
Gross Realized Losses on Investment Sales 1.8  4.2  2.5  5.4 

The base cost of fixed income securities was $1.6 billion and $1.5 billion as of June 30, 2025 and December 31, 2024, respectively.  The base cost of equity securities was $564 million and $549 million as of June 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 June 30, 2025 was as follows:
Fair Value of Fixed
Income Securities
(in millions)
Within 1 year $ 350.0 
After 1 year through 5 years 635.8 
After 5 years through 10 years 231.2 
After 10 years 356.4 
Total $ 1,573.4 

158

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
June 30, 2025
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash $ 48.2  $ —  $ —  $ 3.1  $ 51.3 
Other Cash Deposits (a) —  —  —  16.1  16.1 
Fixed Income Securities – Mutual Funds 156.8  —  —  —  156.8 
Equity Securities – Mutual Funds (b) 39.1  —  —  —  39.1 
Total Other Temporary Investments and Restricted Cash 244.1  —  —  19.2  263.3 
Risk Management Assets
Risk Management Commodity Contracts (c) (d) 2.3  758.9  499.6  (655.5) 605.3 
Cash Flow Hedges:
Commodity Hedges (c) —  128.0  17.5  (22.6) 122.9 
Total Risk Management Assets 2.3  886.9  517.1  (678.1) 728.2 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e) 15.4  —  —  12.7  28.1 
Fixed Income Securities:
United States Government —  1,298.6  —  —  1,298.6 
Corporate Debt —  274.8  —  —  274.8 
Subtotal Fixed Income Securities —  1,573.4  —  —  1,573.4 
Equity Securities – Domestic (b) 3,008.2  —  —  —  3,008.2 
Total Spent Nuclear Fuel and Decommissioning Trusts 3,023.6  1,573.4  —  12.7  4,609.7 
Total Assets $ 3,270.0  $ 2,460.3  $ 517.1  $ (646.2) $ 5,601.2 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (d) $ 4.7  $ 682.0  $ 132.1  $ (576.0) $ 242.8 
Cash Flow Hedges:
Commodity Hedges (c) —  27.3  2.2  (22.5) 7.0 
Fair Value Hedges —  47.9  —  —  47.9 
Total Risk Management Liabilities $ 4.7  $ 757.2  $ 134.3  $ (598.5) $ 297.7 
159


Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2024
Level 1 Level 2 Level 3 Other Total
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 Funds 161.9  —  —  —  161.9 
Equity Securities – Mutual Funds (b) 39.6  —  —  —  39.6 
Total Other Temporary Investments and Restricted Cash 244.6  —  —  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 Assets 2.9  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 
State and Local Government —  —  —  —  — 
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 Trusts 2,847.3  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 

160

AEP Texas
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2025
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Restricted Cash for Securitized Funding $ 13.3  $ —  $ —  $ —  $ 13.3 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) $ —  $ 0.2  $ —  $ (0.2) $ — 

December 31, 2024
Level 1 Level 2 Level 3 Other Total
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) $ — 

161

APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2025
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Restricted Cash for Securitized Funding $ 18.2  $ —  $ —  $ —  $ 18.2 
Risk Management Assets
Risk Management Commodity Contracts (c) —  4.8  108.6  (3.5) 109.9 
Total Assets $ 18.2  $ 4.8  $ 108.6  $ (3.5) $ 128.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) $ —  $ 6.0  $ 0.3  $ (4.0) $ 2.3 



December 31, 2024
Level 1 Level 2 Level 3 Other Total
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 

162

I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2025
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) $ —  $ 17.1  $ 13.0  $ (17.8) $ 12.3 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e) 15.4  —  —  12.7  28.1 
Fixed Income Securities:
United States Government —  1,298.6  —  —  1,298.6 
Corporate Debt —  274.8  —  —  274.8 
State and Local Government —  —  —  —  — 
Subtotal Fixed Income Securities —  1,573.4  —  —  1,573.4 
Equity Securities - Domestic (b) 3,008.2  —  —  —  3,008.2 
Total Spent Nuclear Fuel and Decommissioning Trusts 3,023.6  1,573.4  —  12.7  4,609.7 
Total Assets $ 3,023.6  $ 1,590.5  $ 13.0  $ (5.1) $ 4,622.0 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) $ —  $ 28.1  $ 0.7  $ (27.6) $ 1.2 

December 31, 2024
Level 1 Level 2 Level 3 Other Total
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 Trusts 2,847.3  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 
163

OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2025
Level 1 Level 2 Level 3 Other Total
Liabilities: (in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c) $ —  $ —  $ 47.7  $ —  $ 47.7 

December 31, 2024
Level 1 Level 2 Level 3 Other Total
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
June 30, 2025
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) $ —  $ 3.0  $ 97.0  $ (3.1) $ 96.9 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) $ —  $ 11.2  $ 0.1  $ (3.2) $ 8.1 

December 31, 2024
Level 1 Level 2 Level 3 Other Total
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 
164

SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2025
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Restricted Cash for Securitized Funding $ 16.7  $ —  $ —  $ —  $ 16.7 
Risk Management Assets
Risk Management Commodity Contracts (c) —  1.0  70.7  (1.3) 70.4 
Total Assets $ 16.7  $ 1.0  $ 70.7  $ (1.3) $ 87.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) $ —  $ 3.5  $ 1.6  $ (1.3) $ 3.8 

December 31, 2024
Level 1 Level 2 Level 3 Other Total
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 June 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 $5 million in 2025, $68 million in periods 2026-2028 and $4 million in periods 2029-2030; Level 3 matures $175 million in 2025, $203 million in periods 2026-2028, $12 million in periods 2029-2030 and $(23) 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.

165

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 June 30, 2025 AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Balance as of March 31, 2025 $ 122.8  $ 8.0  $ 3.9  $ (51.2) $ 15.4  $ 13.1 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 52.7  10.1  2.9  (0.2) 17.6  18.6 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 (3.4) —  —  —  —  — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
 (0.8) —  —  —  —  — 
Settlements (101.2) (18.1) (6.9) 2.1  (32.9) (31.7)
Transfers into Level 3 (d) (e) 5.4  —  —  —  —  — 
Transfers out of Level 3 (e) (2.2) —  —  —  —  — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
 309.5  108.3  12.4  1.6  96.8  69.1 
Balance as of June 30, 2025 $ 382.8  $ 108.3  $ 12.3  $ (47.7) $ 96.9  $ 69.1 

Three Months Ended June 30, 2024 AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Balance as of March 31, 2024 $ 119.1  $ 4.0  $ 1.0  $ (41.0) $ 7.7  $ 5.3 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 42.5  15.7  4.1  —  7.5  8.4 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 4.5  —  —  —  —  — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
 0.9  —  —  —  —  — 
Settlements (64.3) (19.7) (5.2) 2.3  (15.2) (13.6)
Transfers into Level 3 (d) (e) 2.5  —  —  —  —  — 
Transfers out of Level 3 (e) (0.2) —  —  —  —  — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
 183.2  67.8  14.6  (4.5) 49.4  38.0 
Balance as of June 30, 2024 $ 288.2  $ 67.8  $ 14.5  $ (43.2) $ 49.4  $ 38.1 
166

Six Months Ended June 30, 2025 AEP APCo I&M OPCo PSO SWEPCo
  (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)
 154.3  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)
 16.8  —  —  —  —  — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) 5.9  —  —  —  —  — 
Settlements (263.2) (84.6) (19.2) 4.3  (57.9) (59.7)
Transfers into Level 3 (d) (e) (0.3) —  —  —  —  — 
Transfers out of Level 3 (e) 0.2  —  —  —  —  — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
 303.5  108.3  12.2  (4.5) 96.9  69.1 
Balance as of June 30, 2025 $ 382.8  $ 108.3  $ 12.3  $ (47.7) $ 96.9  $ 69.1 

Six Months Ended June 30, 2024 AEP APCo I&M OPCo PSO SWEPCo
  (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)
 90.8  24.1  7.3  (0.8) 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)
 13.9  —  —  —  —  — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
 1.7  —  —  —  —  — 
Settlements (158.3) (46.5) (10.0) 4.9  (44.8) (36.0)
Transfers into Level 3 (d) (e) 7.1  —  —  —  —  — 
Transfers out of Level 3 (e) 1.9  —  —  —  —  0.5 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
 191.7  67.8  14.4  3.3  49.4  38.9 
Balance as of June 30, 2024 $ 288.2  $ 67.8  $ 14.5  $ (43.2) $ 49.4  $ 38.1 

(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.
167

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

Significant Unobservable Inputs
June 30, 2025
Significant Input/Range
Type of Fair Value Valuation Unobservable Weighted
Company Input Assets Liabilities Technique Input (a) Low High Average (b)
(in millions)
AEP Energy Contracts $ 204.2  $ 129.7  Discounted Cash Flow Forward Market Price $ 4.80  $ 129.40  $ 47.56 
AEP FTRs 312.9  4.6  Discounted Cash Flow Forward Market Price (32.49) 28.81  (0.20)
APCo FTRs 108.6  0.3  Discounted Cash Flow Forward Market Price (1.40) 14.50  2.10 
I&M FTRs 13.0  0.7  Discounted Cash Flow Forward Market Price (0.90) 14.50  1.05 
OPCo Energy Contracts —  47.7  Discounted Cash Flow Forward Market Price 12.54  75.71  41.08 
PSO FTRs 97.0  0.1  Discounted Cash Flow Forward Market Price (32.49) 5.35  (5.18)
SWEPCo FTRs 70.7  1.6  Discounted Cash Flow Forward Market Price (32.49) 5.35  (5.18)

December 31, 2024
Significant Input/Range
Type of Fair Value Valuation Unobservable Weighted
Company Input Assets Liabilities Technique Input (a) Low High Average (b)
(in millions)
AEP Energy Contracts $ 221.2  $ 144.6  Discounted Cash Flow Forward Market Price $ 2.75  $ 149.30  $ 49.34 
AEP FTRs 92.3  3.3  Discounted Cash Flow Forward Market Price (29.48) 19.70  0.24 
APCo FTRs 35.2  —  Discounted Cash Flow Forward Market Price (0.25) 9.32  1.56 
I&M FTRs 6.9  0.5  Discounted Cash Flow Forward Market Price (4.07) 9.32  1.34 
OPCo Energy Contracts —  47.5  Discounted Cash Flow Forward Market Price 14.53  72.40  42.44 
PSO FTRs 20.8  0.8  Discounted Cash Flow Forward Market Price (29.48) 10.54  (3.88)
SWEPCo FTRs 18.1  0.6  Discounted Cash Flow Forward 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 June 30, 2025 and December 31, 2024:
Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement
Forward Market Price Buy Increase (Decrease) Higher (Lower)
Forward Market Price Sell Increase (Decrease) Lower (Higher)
168

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. In the second quarter of 2025, AEPTCo, APCo, I&M, PSO and SWEPCo recorded tax benefits of $256 million, $24 million, $38 million, $14 million and $46 million, respectively, contributing to a total AEP Consolidated benefit of $383 million, related to the remeasurement of Excess ADIT associated with the FERC order related to the treatment of NOLCs in transmission formula rates, driving a reduction to the interim ETR resulting in AEP’s tax rate of (24.2)% for three months ended June 30, 2025 and (6.4)% for six months ended June 30, 2025 as shown below.

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

Three Months Ended June 30, 2025
AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
U.S. Federal Statutory Rate 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  %
Increase (decrease) due to:
State and Local Income Taxes, Net 0.6  % 0.9  % 2.5  % 0.8  % 1.1  % 1.0  % 3.2  % (2.8) %
Tax Reform Excess ADIT Reversal
 (0.4) % (2.1) % 0.6  % (2.0) % 2.8  % (2.7) % (2.7) % 2.5  %
Remeasurement of Excess ADIT (37.0) % —  % (54.3) % (26.0) % (40.8) % —  % (41.4) % (79.4) %
Production and Investment Tax Credits (6.7) % (0.1) % —  % (0.1) % (18.7) % —  % (69.3) % (40.7) %
Reversal of Origination Flow-Through —  % 0.1  % 0.2  % (4.1) % 1.8  % 0.6  % 0.3  % 0.9  %
AFUDC Equity (1.0) % (1.2) % (0.8) % (0.9) % (0.8) % (1.5) % (1.4) % (1.5) %
Flow-Through of CAMT (0.3) % —  % —  % (3.4) % —  % —  % —  % —  %
Other
 (0.4) % 0.1  % —  % —  % —  % (0.1) % 0.2  % (0.9) %
Effective Income Tax Rate (24.2) % 18.7  % (30.8) % (14.7) % (33.6) % 18.3  % (90.1) % (100.9) %

Three Months Ended June 30, 2024
AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
U.S. Federal Statutory Rate 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  %
Increase (decrease) due to:
State and Local Income Taxes, Net 0.9  % 0.5  % 2.3  % 3.0  % (3.7) % (1.2) % (2.9) % (0.1) %
Tax Reform Excess ADIT Reversal (6.0) % (1.2) % 0.2  % (2.9) % (15.2) % (34.9) % (3.4) % 2.0  %
Remeasurement of Excess ADIT (1.7) % 3.9  % —  % —  % (46.2) % —  % —  % —  %
Production and Investment Tax Credits (11.0) % (0.2) % —  % (0.1) % 1.8  % —  % (70.6) % 15.9  %
Reversal of Origination Flow-Through 1.1  % 0.1  % 0.3  % (1.0) % 12.0  % 2.7  % 0.3  % (0.4) %
Other
 (2.4) % (1.3) % (2.4) % (2.1) % (2.0) % (4.1) % (1.5) % 0.5  %
Effective Income Tax Rate 1.9  % 22.8  % 21.4  % 17.9  % (32.3) % (16.5) % (57.1) % 38.9  %


169

Six Months Ended June 30, 2025
AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
U.S. Federal Statutory Rate 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  %
Increase (decrease) due to:
State and Local Income Taxes, Net 0.9  % 0.6  % 2.5  % 1.0  % 2.0  % 1.3  % 3.0  % (2.2) %
Tax Reform Excess ADIT Reversal
 (1.4) % (2.8) % 0.4  % (2.4) % 0.2  % (3.2) % (3.1) % 0.1  %
Remeasurement of Excess ADIT (19.5) % —  % (34.4) % (8.1) % (24.1) % —  % (23.5) % (45.7) %
Production and Investment Tax Credits (6.6) % (0.1) % —  % (0.1) % (15.8) % —  % (51.3) % (36.6) %
Reversal of Origination Flow-Through 0.2  % 0.1  % 0.2  % (1.8) % 1.8  % 0.7  % 0.2  % 0.8  %
AFUDC Equity (1.1) % (1.1) % (1.1) % (0.7) % (0.7) % (1.6) % (1.0) % (1.4) %
Other
 0.1  % (0.1) % —  % 0.1  % —  % —  % 0.1  % (0.2) %
Effective Income Tax Rate (6.4) % 17.6  % (11.4) % 9.0  % (15.6) % 18.2  % (54.6) % (64.2) %

Six Months Ended June 30, 2024
AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
U.S. Federal Statutory Rate 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  % 21.0  %
Increase (decrease) due to:
State and Local Income Taxes, Net 1.8  % 0.4  % 2.5  % 2.6  % 2.3  % 0.6  % —  % (2.4) %
Tax Reform Excess ADIT Reversal (6.0) % (1.2) % 0.2  % (10.0) % (3.4) % (10.6) % (2.8) % (1.5) %
Remeasurement of Excess ADIT (19.0) % 2.4  % —  % —  % (55.8) % —  % (116.8) % 303.0  %
Production and Investment Tax Credits (7.0) % (0.2) % —  % (0.1) % (0.5) % —  % (61.3) % 69.3  %
Other
 (2.0) % (1.1) % (1.8) % (1.4) % (0.7) % (0.4) % (0.4) % (1.2) %
Effective Income Tax Rate (11.2) % 21.3  % 21.9  % 12.1  % (37.1) % 10.6  % (160.3) % 388.2  %

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 2021. In July 2025, AEP received notification that its 2023 federal income tax return was selected for IRS examination.

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 2021. 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). Most notably for AEP, this budget reconciliation legislation modifies and accelerates the phase out of wind and solar PTCs and ITCs, adds new restrictions to guard against certain foreign ownership or influence with respect to otherwise credit-eligible projects and makes 100% bonus depreciation permanent for our non-regulated entities. With the exception of bonus depreciation, this legislation is prospective and has no material impact on the current period financial statements. Following enactment of the legislation, on July 7, 2025, the President issued an Executive Order directing the Department of Treasury to issue new and revised wind and solar tax credit guidance within 45 days, which could impose further practical limits on the development of wind and solar projects. In addition to this potential near term guidance, additional significant guidance from the Department of Treasury and the IRS is expected on the tax provisions included in the OBBBA. AEP will continue to monitor any issued guidance and evaluate the impact on future net income, cash flows and financial condition.
170

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.

AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(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 June 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.
171

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 six months ended June 30, 2025. Approximately $1.3 billion of equity is available for issuance under the ATM program upon the filing of a prospectus supplement.

Forward Sale of Equity

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

Long-term Debt Outstanding (Applies to AEP)

The following table details long-term debt outstanding, net of issuance costs and premiums or discounts:
Type of Debt June 30, 2025 December 31, 2024
  (in millions)
Senior Unsecured Notes $ 37,019.1  $ 36,410.9 
Pollution Control Bonds 1,730.3  1,771.3 
Notes Payable 644.5  609.9 
Securitization Bonds 1,021.0  578.0 
Spent Nuclear Fuel Obligation (a) 323.2  316.3 
Junior Subordinated Notes 2,581.2  2,579.1 
Other Long-term Debt 1,206.2  377.3 
Total Long-term Debt Outstanding 44,525.5  42,642.8 
Long-term Debt Due Within One Year 3,212.4  3,335.0 
Long-term Debt $ 41,313.1  $ 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 $375 million and $367 million as of June 30, 2025 and December 31, 2024, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.


172

Long-term Debt Activity

Long-term debt and other securities issued, retired and principal payments made during the first six months of 2025 are shown in the following tables:
Principal Interest
Company Type of Debt Amount (a) Rate Due Date
Issuances:   (in millions) (%)
AEP Texas Other Long-term Debt $ 400.0  Variable 2026
AEPTCo Senior Unsecured Notes 425.0  5.38 2035
APCo Other Long-term Debt 425.0  Variable 2026
APCo Pollution Control Bonds 104.4  3.70 2028
I&M Notes Payable 100.0  4.89 2029
I&M Pollution Control Bonds 150.0 3.70 2029
PSO Senior Unsecured Notes 800.0  5.45 2036
Non-Registrant:
KPCo Other Long-term Debt 150.0  Variable 2026
KPCo Securitization Bonds 477.7  5.30 2045
Transource Energy Other Long-term Debt 29.5  Variable 2025
WPCo Other Long-term Debt 125.0  Variable 2026
Total Issuances $ 3,186.6 

(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.

173

Principal Interest
Company Type of Debt Amount Paid Rate Due Date
Retirements and Principal Payments:
 (in millions) (%)
AEP Texas Securitization Bonds $ 10.3  2.06 2025
AEP Texas Securitization Bonds 1.9  2.29 2029
AEPTCo Senior Unsecured Notes 50.0  3.66 2025
AEPTCo Senior Unsecured Notes 40.0  3.76 2025
APCo Other Long-term Debt 0.1  13.72 2026
APCo Pollution Control Bonds 104.4  3.75 2025
APCo Securitization Bonds 13.9  3.77 2028
APCo Senior Unsecured Notes 300.0  3.40 2025
I&M Notes Payable 1.1  Variable 2025
I&M Notes Payable 2.6  0.93 2025
I&M Notes Payable 7.5  3.44 2026
I&M Notes Payable 8.7  5.93 2027
I&M Notes Payable 10.1  6.01 2028
I&M Notes Payable 16.3  6.41 2028
I&M Notes Payable 3.5  4.89 2029
I&M Other Long-term Debt 0.2  6.00 2025
I&M Pollution Control Bonds 40.0  0.75 2025
I&M Pollution Control Bonds 50.0  2.75 2025
I&M Pollution Control Bonds 100.0  3.05 2025
PSO Other Long-term Debt 0.3  3.00 2027
PSO Senior Unsecured Notes 125.0  3.17 2025
Non-Registrant:
KPCo Other Long-term Debt 150.0  Variable 2025
KPCo Other Long-term Debt 150.0  Variable 2026
Transource Energy Senior Unsecured Notes 1.2  2.75 2050
WPCo Senior Unsecured Notes 122.0  3.70 2025
WPCo Notes Payable 15.0  6.89 2034
Total Retirements and Principal Payments
 $ 1,324.1 

Financing Activities Subsequent Events

In July 2025, AEGCo retired $45 million of Pollution Control Bonds.

In July 2025, I&M retired $10 million of Notes Payable related to DCC Fuel.

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

In July 2025, AEP made a capital contribution of $200 million to AEP Texas.

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 0.3% of consolidated tangible net assets as of June 30, 2025. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreements.


174

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 June 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 six months ended June 30, 2025 are described in the following table:
Maximum Average Net Loans to
Borrowings Maximum Borrowings Average (Borrowings from) Authorized
from the Loans to the from the Loans to the the Utility Money Short-term
Utility Utility Utility Utility Pool as of Borrowing
Company Money Pool Money Pool Money Pool Money Pool June 30, 2025 Limit
  (in millions)
AEP Texas $ 468.4  $ 112.8  $ 182.7  $ 62.5  $ (109.5) $ 600.0 
AEPTCo 403.6  312.2  192.0  39.8  32.7  820.0  (a)
APCo 263.5  242.1  141.3  30.0  (154.8) 750.0 
I&M 145.2  19.3  77.2  6.1  (25.7) 500.0 
OPCo 270.9  165.9  71.6  81.7  (203.0) 600.0 
PSO 505.1  391.5  204.1  167.0  (319.7) 750.0 
SWEPCo 471.9  76.3  285.9  10.2  76.3  750.0 

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



175

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 June 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 six months ended June 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
Company Money Pool Money Pool June 30, 2025
(in millions)
AEP Texas $ 7.2  $ 7.1  $ 7.1 
SWEPCo 2.4  2.3  2.4 

AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of borrowings from AEP as of June 30, 2025 and December 31, 2024 are included in Advances from Affiliates on AEPTCo’s balance sheets. AEPTCo’s direct financing activities with AEP and corresponding authorized borrowing limit for the six months ended June 30, 2025 are described in the following table:
Borrowings Authorized
Maximum Maximum Average Average from AEP Loans to Short-term
Borrowings Loans Borrowings Loans as of AEP as of Borrowing
Company from AEP   to AEP   from AEP   to AEP   June 30, 2025 June 30, 2025 Limit (a)
(in millions)
AEPTCo Parent $ 106.6  $ 132.6  $ 13.6  $ 38.2  $ 10.5  $ —  $ — 
SWTCo 2.0  —  1.9  —  2.0  —  50.0 
Midwest Transmission Holdings —  32.6  —  11.0  —  —  — 

(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:
  Six Months Ended June 30,
2025 2024
Maximum Interest Rate 4.83  % 5.79  %
Minimum Interest Rate 4.14  % 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 Funds Average Interest Rate for Funds
Borrowed from the Utility Money Pool Loaned to the Utility Money Pool
for Six Months Ended June 30, for Six Months Ended June 30,
Company 2025 2024 2025 2024
AEP Texas 4.69  % 5.70  % 4.72  % 5.49  %
AEPTCo 4.68  % 5.71  % 4.62  % 5.62  %
APCo 4.69  % 5.73  % 4.58  % 5.64  %
I&M 4.69  % 5.67  % 4.64  % 5.68  %
OPCo 4.65  % 5.70  % 4.70  % 5.52  %
PSO 4.67  % 5.64  % 4.68  % —  %
SWEPCo 4.69  % 5.64  % 4.65  % —  %

176

Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:
Six Months Ended June 30, 2025 Six Months Ended June 30, 2024
    Maximum   Minimum   Average Maximum   Minimum   Average
    Interest Rate   Interest Rate   Interest Rate Interest Rate   Interest Rate   Interest Rate
    for Funds   for Funds   for Funds for Funds   for Funds   for Funds
  Loaned to   Loaned to   Loaned to Loaned to   Loaned to   Loaned to
  the Nonutility   the Nonutility   the Nonutility the Nonutility   the Nonutility   the Nonutility
Company   Money Pool   Money Pool   Money Pool Money Pool   Money Pool   Money Pool
AEP Texas   4.76  % 4.64  % 4.70  % 5.79  % 5.56  % 5.69  %
SWEPCo   4.76  % 4.64  % 4.70  % 5.79  % 5.56  % 5.68  %

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

  Maximum Minimum Maximum Minimum Average Average
  Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
Six Months   for Funds for Funds for Funds for Funds for Funds for Funds
Ended   Borrowed Borrowed Loaned Loaned Borrowed Loaned
June 30,   from AEP   from AEP to AEP   to AEP   from AEP   to AEP
2025   4.76  % 4.63  % 4.76  % 4.63  % 4.69  % 4.69  %
2024   5.79  % 5.55  % 5.79  % 5.55  % 5.68  % 5.68  %

Short-term Debt (Applies to AEP and SWEPCo)

Outstanding short-term debt was as follows:
  June 30, 2025 December 31, 2024
Outstanding Interest Outstanding Interest
Company Type of Debt Amount Rate (a) Amount Rate (a)
  (dollars in millions)
AEP Securitized Debt for Receivables (b) $ 900.0  4.57  % $ 900.0  4.73  %
AEP Commercial Paper 600.0  4.62  % 1,618.3  4.70  %
SWEPCo Notes Payable 1.6  6.68  % 5.5  6.69  %
Total Short-term Debt $ 1,501.6    $ 2,523.8   

(a)Weighted-average rate as of June 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.


177

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 2026. As of June 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 June 30, Six Months Ended June 30,
2025 2024 2025 2024
(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable
 4.53  % 5.51  % 4.57  % 5.56  %
Net Uncollectible Accounts Receivable Written-Off $ 6.1  $ 5.8  $ 13.9  $ 13.9 

June 30, 2025 December 31, 2024
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts
 $ 1,233.9  $ 1,117.0 
Short-term – Securitized Debt of Receivables 900.0  900.0 
Delinquent Securitized Accounts Receivable 58.5  56.2 
Bad Debt Reserves Related to Securitization 45.1  44.5 
Unbilled Receivables Related to Securitization 390.6  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:
Company June 30, 2025 December 31, 2024
  (in millions)
APCo $ 197.4  $ 192.7 
I&M 182.9  160.5 
OPCo 477.4  470.7 
PSO 158.1  111.4 
SWEPCo 189.7  153.5 

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The fees paid to AEP Credit for customer accounts receivable sold were:
  Three Months Ended June 30, Six Months Ended June 30,
Company 2025 2024 2025 2024
  (in millions)
APCo $ 3.3  $ 3.9  $ 7.2  $ 8.1 
I&M 3.5  3.8  7.0  7.9 
OPCo 7.5  7.4  14.9  14.8 
PSO 2.8  3.4  5.7  6.8 
SWEPCo 3.7  4.3  7.8  9.1 
The proceeds on the sale of receivables to AEP Credit were:
  Three Months Ended June 30, Six Months Ended June 30,
Company 2025 2024 2025 2024
(in millions)
APCo $ 429.8  $ 447.3  $ 1,034.6  $ 983.3 
I&M 545.4  502.1  1,130.2  1,031.8 
OPCo 735.2  771.5  1,595.5  1,617.2 
PSO 431.9  425.0  806.7  786.6 
SWEPCo 456.0  471.9  884.1  897.3 

179

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 June 30, 2025, $9 million of the securitized bonds was included in Long-term Debt Due Within One Year and $459 million was included in Long-term Debt on the balance sheet. Cost Recovery Funding’s securitized assets were $468 million as of June 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 other Registrants’ consolidated VIEs.
180

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

June 30, 2025
Consolidated VIEs
SWEPCo
Sabine		 I&M
DCC Fuel		 AEP Texas Restoration Funding APCo Appalachian Consumer Rate Relief Funding SWEPCo Storm Recovery Funding KPCo Cost Recovery Funding AEP Credit Protected
Cell
of EIS		 Transource Energy
(in millions)
ASSETS
Current Assets $ 3.1  $ 95.0  $ 18.6  $ 16.0  $ 18.1  $ 3.1  $ 1,235.0  $ 209.9  $ 58.6 
Net Property, Plant and Equipment —  181.1  —  —  —  —  —  —  621.8 
Other Noncurrent Assets 97.1  98.1  110.6  (a) 93.7  (b) 324.7  469.4  (c) 10.7  —  7.9 
Total Assets $ 100.2  $ 374.2  $ 129.2  $ 109.7  $ 342.8  $ 472.5  $ 1,245.7  $ 209.9  $ 688.3 
LIABILITIES AND EQUITY
Current Liabilities $ 16.6  $ 94.8  $ 30.7  $ 30.8  $ 28.5  $ 10.7  $ 1,179.5  $ 46.6  $ 30.1 
Noncurrent Liabilities 83.4  279.4  97.2  77.0  312.6  459.4  1.0  105.6  333.1 
Equity 0.2  —  1.3  1.9  1.7  2.4  65.2  57.7  325.1 
Total Liabilities and Equity $ 100.2  $ 374.2  $ 129.2  $ 109.7  $ 342.8  $ 472.5  $ 1,245.7  $ 209.9  $ 688.3 

(a)Includes an intercompany item eliminated in consolidation of $5 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 Funding APCo
Appalachian
Consumer
Rate Relief Funding		 SWEPCo Storm Recovery Funding AEP Credit Protected
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 Assets 110.8 63.6 121.9  (a) 109.6 (b) 331.4 10.5  —  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 Liabilities 96.3  196.0  111.2  91.4 308.7 1.0 96.0  274.3 
Equity 0.4 —  1.3 1.9 1.7 59.0  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.


Significant Variable Interests in Non-Consolidated VIEs and Significant Equity Method Investments

The 2024 Annual Report includes a detailed discussion of significant variable interests in non-consolidated VIEs and other significant equity method investments.

181

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 June 30, 2025
(in millions)
AEP (b)(c)(d)(e)(f)(g) $ 3,611.7  $ 84.6  $ 17.4  $ (42.4) $ 34.8  $ 3,706.1 
PSO (b)(e)(f)(g) 121.8  3.6  15.5  (1.3) (2.8) 136.8 
SWEPCo (b)(d)(e)(f) 278.7  8.7  —  (27.5) 31.6  291.5 

(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 and Flat Ridge IV Wind Energy Facility. See the “Acquisitions” section of Note 6 for additional information.


182

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 June 30, 2025
VIU T&D AEPTHCo G&M Corporate and Other Reconciling Adjustments AEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues $ 1,029.7  $ 611.8  $ —  $ —  $ —  $ —  $ 1,641.5 
Commercial Revenues 749.5  420.6  —  —  —  —  1,170.1 
Industrial Revenues (a) 704.6  145.1  —  —  —  (0.3) 849.4 
Other Retail Revenues 60.5  14.1  —  —  —  —  74.6 
Total Retail Revenues 2,544.3  1,191.6  —  —  —  (0.3) 3,735.6 
Wholesale and Competitive Retail Revenues:
Generation Revenues 237.3  —  —  38.3  —  —  275.6 
Transmission Revenues (b) 157.2  197.4  698.3  —  —  (622.1) 430.8 
Retail, Trading and Marketing Revenues (c) —  —  —  538.6  —  (15.3) 523.3 
Total Wholesale and Competitive Retail Revenues
 394.5  197.4  698.3  576.9  —  (637.4) 1,229.7 
Other Revenues from Contracts with Customers (d) 49.4  46.2  8.9  2.4  27.4  (44.2) 90.1 
Total Revenues from Contracts with Customers
 2,988.2  1,435.2  707.2  579.3  27.4  (681.9) 5,055.4 
Other Revenues:
Alternative Revenue Programs (a) (e) 14.5  12.4  49.5  —  —  (47.0) 29.4 
Other Revenues (a) (f) 12.5  2.6  (0.1) (13.1) 2.2  (2.0) 2.1 
Total Other Revenues 27.0  15.0  49.4  (13.1) 2.2  (49.0) 31.5 
Total Revenues $ 3,015.2  $ 1,450.2  $ 756.6  $ 566.2  $ 29.6  $ (730.9) $ 5,086.9 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $558 million. The affiliated revenues for Vertically Integrated Utilities were $65 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $16 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $26 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.
183

Three Months Ended June 30, 2024
VIU T&D AEPTHCo G&M Corporate and Other Reconciling Adjustments AEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues $ 949.0  $ 650.2  $ —  $ —  $ —  $ —  $ 1,599.2 
Commercial Revenues 649.8  391.1  —  —  —  —  1,040.9 
Industrial Revenues (a) 652.8  123.0  —  —  —  (0.1) 775.7 
Other Retail Revenues 55.8  13.7  —  —  —  —  69.5 
Total Retail Revenues 2,307.4  1,178.0  —  —  —  (0.1) 3,485.3 
Wholesale and Competitive Retail Revenues:
Generation Revenues 149.0  —  —  23.7  —  (0.1) 172.6 
Transmission Revenues (b) 123.0  208.3  496.6  —  —  (397.0) 430.9 
Renewable Generation Revenues (a) —  —  —  8.2  —  (1.4) 6.8 
Retail, Trading and Marketing Revenues (c) —  —  —  485.5  0.3  (23.7) 462.1 
Total Wholesale and Competitive Retail Revenues
 272.0  208.3  496.6  517.4  0.3  (422.2) 1,072.4 
Other Revenues from Contracts with Customers (d) 47.4  38.9  6.2  1.0  55.2  (48.8) 99.9 
Total Revenues from Contracts with Customers
 2,626.8  1,425.2  502.8  518.4  55.5  (471.1) 4,657.6 
Other Revenues:
Alternative Revenue Programs (a) (e) (12.1) 6.7  (12.9) —  —  (17.3) (35.6)
Other Revenues (a) (f) 4.3  4.0  —  (50.9) 2.2  (2.4) (42.8)
Total Other Revenues (7.8) 10.7  (12.9) (50.9) 2.2  (19.7) (78.4)
Total Revenues $ 2,619.0  $ 1,435.9  $ 489.9  $ 467.5  $ 57.7  $ (490.8) $ 4,579.2 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $393 million. The affiliated revenues for Vertically Integrated Utilities were $41 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $24 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $30 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.

184

Three Months Ended June 30, 2025
AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Retail Revenues:
Residential Revenues $ 180.2  $ —  $ 365.2  $ 190.1  $ 431.5  $ 190.4  $ 191.3 
Commercial Revenues 114.6  —  194.0  192.2  306.2  135.2  155.4 
Industrial Revenues (a) 41.7  —  210.5  156.7  103.5  91.3  103.2 
Other Retail Revenues 10.1  —  28.2  1.3  4.1  26.4  2.7 
Total Retail Revenues 346.6  —  797.9  540.3  845.3  443.3  452.6 
Wholesale Revenues:
Generation Revenues (b) —  —  77.9  138.2  —  1.5  48.6 
Transmission Revenues (c) 175.4  682.3  45.9  18.6  22.0  16.0  55.4 
Total Wholesale Revenues 175.4  682.3  123.8  156.8  22.0  17.5  104.0 
Other Revenues from Contracts with Customers (d) 9.1  8.9  18.5  26.9  37.3  6.8  5.7 
Total Revenues from Contracts with Customers
 531.1  691.2  940.2  724.0  904.6  467.6  562.3 
Other Revenues:
Alternative Revenue Programs (a) (e) 0.4  50.5  7.2  1.2  12.1  1.8  8.0 
Other Revenues (a) (0.3) 0.1  0.2  12.0  2.3  0.1  0.1 
Total Other Revenues 0.1  50.6  7.4  13.2  14.4  1.9  8.1 
Total Revenues $ 531.2  $ 741.8  $ 947.6  $ 737.2  $ 919.0  $ 469.5  $ 570.4 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $36 million primarily related to the PPA with KGPCo.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $555 million, $22 million and $21 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.

185

Three Months Ended June 30, 2024
AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Retail Revenues:
Residential Revenues $ 184.9  $ —  $ 364.8  $ 190.5  $ 465.3  $ 187.8  $ 120.7 
Commercial Revenues 115.0  —  187.1  150.8  276.1  130.1  100.7 
Industrial Revenues (a) 34.0  —  205.9  153.1  89.0  91.1  72.3 
Other Retail Revenues 9.3  —  28.1  1.3  4.5  25.9  1.7 
Total Retail Revenues 343.2  —  785.9  495.7  834.9  434.9  295.4 
Wholesale Revenues:
Generation Revenues (b) —  —  72.1  54.8  —  2.7  50.1 
Transmission Revenues (c) 184.8  483.2  45.6  10.0  23.6  10.2  46.7 
Total Wholesale Revenues 184.8  483.2  117.7  64.8  23.6  12.9  96.8 
Other Revenues from Contracts with Customers (d) 10.4  6.2  13.1  29.4  28.5  12.4  7.6 
Total Revenues from Contracts with Customers
 538.4  489.4  916.7  589.9  887.0  460.2  399.8 
Other Revenues:
Alternative Revenue Programs (a) (e) 1.2  (14.2) (6.5) —  5.3  (1.4) (4.0)
Other Revenues (a) —  —  —  4.4  4.0  —  — 
Total Other Revenues 1.2  (14.2) (6.5) 4.4  9.3  (1.4) (4.0)
Total Revenues $ 539.6  $ 475.2  $ 910.2  $ 594.3  $ 896.3  $ 458.8  $ 395.8 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $36 million primarily related to the PPA with KGPCo.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $389 million, $22 million and $15 million, respectively. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $23 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.



186

Six Months Ended June 30, 2025
VIU T&D AEPTHCo G&M Corporate and Other Reconciling Adjustments AEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues $ 2,382.0  $ 1,350.8  $ —  $ —  $ —  $ —  $ 3,732.8 
Commercial Revenues 1,414.7  802.3  —  —  —  —  2,217.0 
Industrial Revenues (a) 1,322.4  268.2  —  —  —  (0.5) 1,590.1 
Other Retail Revenues 114.9  29.5  —  —  —  —  144.4 
Total Retail Revenues 5,234.0  2,450.8  —  —  —  (0.5) 7,684.3 
Wholesale and Competitive Retail Revenues:
Generation Revenues 542.3  —  —  89.3  —  —  631.6 
Transmission Revenues (b) 278.1  394.4  1,219.7  —  —  (1,072.3) 819.9 
Retail, Trading and Marketing Revenues (c) —  —  —  1,160.2  (0.2) (31.5) 1,128.5 
Total Wholesale and Competitive Retail Revenues 820.4  394.4  1,219.7  1,249.5  (0.2) (1,103.8) 2,580.0 
Other Revenues from Contracts with Customers (d) 101.0  108.1  17.7  3.4  70.6  (94.6) 206.2 
Total Revenues from Contracts with Customers
 6,155.4  2,953.3  1,237.4  1,252.9  70.4  (1,198.9) 10,470.5 
Other Revenues:
Alternative Revenue Programs (a) (e) 17.8  15.9  61.3  —  —  (62.3) 32.7 
Other Revenues (a) (f) (20.2) 7.5  —  60.2  3.8  (4.2) 47.1 
Total Other Revenues (2.4) 23.4  61.3  60.2  3.8  (66.5) 79.8 
Total Revenues $ 6,153.0  $ 2,976.7  $ 1,298.7  $ 1,313.1  $ 74.2  $ (1,265.4) $ 10,550.3 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $969 million. The affiliated revenues for Vertically Integrated Utilities were $104 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $32 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $55 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.
187

Six Months Ended June 30, 2024
VIU T&D AEPTHCo G&M Corporate and Other Reconciling Adjustments AEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues $ 2,161.3  $ 1,354.0  $ —  $ —  $ —  $ —  $ 3,515.3 
Commercial Revenues 1,294.9  788.1  —  —  —  —  2,083.0 
Industrial Revenues (a) 1,299.9  259.1  —  —  —  (0.3) 1,558.7 
Other Retail Revenues 111.1  27.6  —  —  —  —  138.7 
Total Retail Revenues 4,867.2  2,428.8  —  —  —  (0.3) 7,295.7 
Wholesale and Competitive Retail Revenues:
Generation Revenues 384.9  —  —  51.1  —  —  436.0 
Transmission Revenues (b) 241.9  388.1  985.3  —  —  (815.6) 799.7 
Renewable Generation Revenues (a) —  —  —  14.5  —  (2.8) 11.7 
Retail, Trading and Marketing Revenues (c)
 —  —  —  1,056.9  0.8  (69.9) 987.8 
Total Wholesale and Competitive Retail Revenues
 626.8  388.1  985.3  1,122.5  0.8  (888.3) 2,235.2 
Other Revenues from Contracts with Customers (d) 107.1  89.9  14.3  2.3  115.6  (117.5) 211.7 
Total Revenues from Contracts with Customers
 5,601.1  2,906.8  999.6  1,124.8  116.4  (1,006.1) 9,742.6 
Other Revenues:
Alternative Revenue Programs (a) (e) (12.8) 7.4  (12.4) —  —  (16.3) (34.1)
Other Revenues (a) (f) (21.4) 11.9  —  (93.8) (5.9) 5.6  (103.6)
Total Other Revenues (34.2) 19.3  (12.4) (93.8) (5.9) (10.7) (137.7)
Total Revenues $ 5,566.9  $ 2,926.1  $ 987.2  $ 1,031.0  $ 110.5  $ (1,016.8) $ 9,604.9 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $780 million. The affiliated revenues for Vertically Integrated Utilities were $83 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $70 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $79 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.
188

Six Months Ended June 30, 2025
AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Retail Revenues:
Residential Revenues $ 352.1  $ —  $ 971.6  $ 422.2  $ 998.7  $ 365.7  $ 383.9 
Commercial Revenues 233.9  —  388.5  344.7  568.5  237.1  296.1 
Industrial Revenues (a) 81.2  —  401.9  290.4  187.0  161.7  192.9 
Other Retail Revenues 21.0  —  56.4  2.5  8.6  46.6  5.4 
Total Retail Revenues 688.2  —  1,818.4  1,059.8  1,762.8  811.1  878.3 
Wholesale Revenues:
Generation Revenues (b) —  —  167.5  333.3  —  5.6  104.3 
Transmission Revenues (c) 348.7  1,188.2  87.7  29.0  45.7  29.8  94.3 
Total Wholesale Revenues 348.7  1,188.2  255.2  362.3  45.7  35.4  198.6 
Other Revenues from Contracts with
Customers (d)
 18.6  17.8  32.9  56.9  89.6  15.1  15.8 
Total Revenues from Contracts with Customers 1,055.5  1,206.0  2,106.5  1,479.0  1,898.1  861.6  1,092.7 
Other Revenues:
Alternative Revenue Program (a) (e) (1.1) 62.9  13.7  1.0  17.1  1.9  8.8 
Other Revenues (a) (0.2) —  0.3  (20.6) 7.3  —  — 
Total Other Revenues (1.3) 62.9  14.0  (19.6) 24.4  1.9  8.8 
Total Revenues $ 1,054.2  $ 1,268.9  $ 2,120.5  $ 1,459.4  $ 1,922.5  $ 863.5  $ 1,101.5 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $81 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 $962 million, $41 million and $31 million, respectively. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $36 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.
189

Six Months Ended June 30, 2024
AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
Retail Revenues:
Residential Revenues $ 332.2  $ —  $ 891.1  $ 415.3  $ 1,021.8  $ 346.0  $ 303.1 
Commercial Revenues 225.9  —  375.4  295.6  562.2  233.1  240.7 
Industrial Revenues (a) 69.6  —  402.3  301.0  189.5  171.4  167.3 
Other Retail Revenues 19.0  —  56.2  2.6  8.7  47.4  4.3 
Total Retail Revenues 646.7  —  1,725.0  1,014.5  1,782.2  797.9  715.4 
Wholesale Revenues:
Generation Revenues (b) —  —  157.2  192.1  —  4.9  97.2 
Transmission Revenues (c) 340.7  958.6  92.7  20.1  47.4  21.0  86.3 
Total Wholesale Revenues 340.7  958.6  249.9  212.2  47.4  25.9  183.5 
Other Revenues from Contracts with
Customers (d)
 19.2  14.3  34.8  57.0  70.7  24.4  17.2 
Total Revenues from Contracts with Customers 1,006.6  972.9  2,009.7  1,283.7  1,900.3  848.2  916.1 
Other Revenues:
Alternative Revenue Programs (a) (e) (0.6) (14.9) (6.6) (0.5) 7.9  (1.6) (4.1)
Other Revenues (a) —  —  0.1  (21.5) 11.9  —  — 
Total Other Revenues (0.6) (14.9) (6.5) (22.0) 19.8  (1.6) (4.1)
Total Revenues $ 1,006.0  $ 958.0  $ 2,003.2  $ 1,261.7  $ 1,920.1  $ 846.6  $ 912.0 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $77 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 $773 million, $43 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 $41 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 June 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.
Company 2025 2026-2027 2028-2029 After 2029 Total
(in millions)
AEP $ 43.7  $ 143.6  $ 48.6  $ 16.1  $ 252.0 
APCo 8.0  31.9  25.2  11.4  76.5 
I&M 2.2  8.8  6.8  2.4  20.2 


190

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 June 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 June 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 June 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 Texas AEPTCo APCo I&M OPCo PSO SWEPCo
(in millions)
June 30, 2025 $ 1.4  $ 165.0  $ 80.9  $ 58.1  $ 61.7  $ 16.8  $ 25.8 
December 31, 2024 —  131.6  83.7  55.0  63.6  13.0  21.4 

191

CONTROLS AND PROCEDURES

During the second 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 June 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 second quarter of 2025 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
192

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. As of June 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.

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

None.

Item 3.  Defaults Upon Senior Securities

None.

Item 4.  Mine Safety Disclosures

Not applicable.

Item 5.  Other Information

On May 15, 2025, Benjamin G. S. Fowke, III, a director of the Company, entered into a Rule 10b5-1 trading agreement (“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. Fowke’s Rule 10b5-1 Trading Plan provides for an aggregate sale of up to 25,000 shares of common stock through December 12, 2025.

On May 15, 2025, Kelly J. Ferneau, the Executive Vice President and Chief Nuclear 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. Ms. Ferneau’s Rule 10b5-1 Trading Plan provides for an aggregate sale of up to 10,218 shares of common stock through February 23, 2026.

During the three months ended June 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).

193

Item 6.  Exhibits

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

Exhibit Description Previously Filed as Exhibit to:
AEPTCo‡   File No. 3-217143
*4(a) Company Order and Officers’ Certificate between AEPTCo and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated May 14, 2025, establishing terms of the Notes.
PSO‡   File No. 0-343
*4(a) Thirteenth Supplemental Indenture, dated June 1, 2025, between PSO and The Bank of New York Mellon Trust Company, N.A., as Trustee, establishing terms of the Notes.

The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.
Exhibit Description AEP AEP
Texas		 AEPTCo APCo I&M OPCo PSO SWEPCo
10(a) Amended and Restated Limited Liability Company Agreement, dated June 5, 2025, among AEP Transmission Company, LLC, Midwest Transmission Holdings, LLC and Olympus BidCo L.P.
31(a)
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31(b)
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32(a)
Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
32(b)
Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
101.INS
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194

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
Controller and Chief Accounting Officer
(Principal Accounting Officer and Authorized Signatory)



Date:  July 30, 2025
195
EX-10.A 2 ex10aaeptco20252q.htm EX-10.A Document










AMENDED AND RESTATED
LIMITED LIABILITY COMPANY AGREEMENT
OF
MIDWEST TRANSMISSION HOLDINGS, LLC


TABLE OF CONTENTS

Page

ARTICLE I GENERAL MATTERS    1
Section 1.1    Formation    1
Section 1.2    Name    1
Section 1.3    Purpose    2
Section 1.4    Registered Office    2
Section 1.5    Registered Agent    2
Section 1.6    Members    2
Section 1.7    Powers    3
Section 1.8    Limited Liability Company Agreement    3
Section 1.9    Issuance of Additional Membership Interests    4
Section 1.10    No State Law Partnership    4
ARTICLE II MANAGEMENT    4
Section 2.1    Managers    4
Section 2.2    Number of Managers; Proportional Appointment Rights    4
Section 2.3    Removal of Managers    6
Section 2.4    Vacancies    7
Section 2.5    Acts of the Board; Voting    7
Section 2.6    Compensation of Managers    7
Section 2.7    Meetings of Managers; Notice    7
Section 2.8    Quorum    8
Section 2.9    Place and Method of Meetings    8
Section 2.10    Action by the Board Without a Meeting    9
Section 2.11    Duties of Managers    9
Section 2.12    Committees    9
Section 2.13    Investor Member Board Observer    10
Section 2.14    Related Party Matters    11
Section 2.15    D&O Insurance    13
ARTICLE III OFFICERS    13
Section 3.1    Appointment and Tenure    13
-i-


TABLE OF CONTENTS
(continued)
Page

Section 3.2    Removal    13
Section 3.3    President    13
Section 3.4    Vice Presidents    14
Section 3.5    Secretary; Assistant Secretaries    14
Section 3.6    Treasurer; Assistant Treasurers    14
Section 3.7    Duties of Officers; Limitations of Authority    14
ARTICLE IV DEFAULT; DISSOLUTION    15
Section 4.1    Events of Default    15
Section 4.2    Default Notice    15
Section 4.3    Dissolution    15
ARTICLE V CAPITAL CONTRIBUTIONS; DISTRIBUTIONS    16
Section 5.1    Capital Contributions    16
Section 5.2    Distributions Generally; Support Payments    21
Section 5.3    Distributions upon the Occurrence of an Event of Dissolution    22
Section 5.4    Withdrawal of Capital; Interest    22
ARTICLE VI TRANSFERS OF MEMBERSHIP INTERESTS    22
Section 6.1    General Restriction    22
Section 6.2    Transfers to Permitted Transferees; Liens by Members    22
Section 6.3    Right of First Offer    23
Section 6.4    Tag-Along Rights    26
Section 6.5    Drag-Along Rights    27
Section 6.6    Put Option    30
Section 6.7    Cooperation    31
ARTICLE VII PREEMPTIVE RIGHTS    32
Section 7.1    Preemptive Rights    32
ARTICLE VIII PROTECTIVE PROVISIONS    33
Section 8.1    Investor Member No Threshold Matters    33
Section 8.2    Investor Member Threshold Matters    34
Section 8.3    Consultation Matters    37
-ii-


TABLE OF CONTENTS
(continued)
Page

Section 8.4    Actions by the Investor Manager on behalf of the Investor Member    37
Section 8.5    Acknowledgement of Purpose of Provisions    38
ARTICLE IX OTHER COVENANTS AND AGREEMENTS    38
Section 9.1    Books and Records    38
Section 9.2    Financial Reports    39
Section 9.3    Other Business; Corporate Opportunities    40
Section 9.4    Compliance with Laws    41
Section 9.5    Non-Solicit    42
Section 9.6    Confidentiality    43
Section 9.7    Expenses    44
Section 9.8    Corporate Transparency Act Compliance    44
Section 9.9    Obligations in Respect of Financings    45
ARTICLE X TAX MATTERS    45
Section 10.1    Tax Classification    45
Section 10.2    Tax Matters Shareholder    45
Section 10.3    Tax Allocation Agreement    46
Section 10.4    Cooperation    46
Section 10.5    Withholding    46
Section 10.6    Certain Representations and Warranties    47
Section 10.7    Intended Tax Treatment    47
ARTICLE XI LIABILITY; EXCULPATION; INDEMNIFICATION    47
Section 11.1    Liability; Member Duties    47
Section 11.2    Exculpation    47
Section 11.3    Indemnification    48
Section 11.4    Authorization    48
Section 11.5    Reliance on Information    48
Section 11.6    Advancement of Expenses    49
Section 11.7    Non-Exclusive Provisions    49
Section 11.8    Survival of Indemnification and Advancement of Expenses    49
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TABLE OF CONTENTS
(continued)
Page

Section 11.9    Limitations    49
ARTICLE XII REPRESENTATIONS AND WARRANTIES    50
Section 12.1    Members Representations and Warranties    50
ARTICLE XIII MISCELLANEOUS    50
Section 13.1    Notices    50
Section 13.2    Assignment    52
Section 13.3    Waiver of Partition    52
Section 13.4    Further Assurances    52
Section 13.5    Third Party Beneficiaries    52
Section 13.6    Parties in Interest    53
Section 13.7    Severability    53
Section 13.8    Construction    53
Section 13.9    Complete Agreement    53
Section 13.10    Amendment; Waiver    53
Section 13.11    Governing Law    54
Section 13.12    Specific Performance    54
Section 13.13    Escalation; Arbitration    54
Section 13.14    Counterparts    56
Section 13.15    Fair Market Value Determination    56
Section 13.16    Certain Definitions    57
Section 13.17    Terms Defined Elsewhere in this Agreement    71
Section 13.18    Other Definitional Provisions    72
Schedules
Schedule 1 – Schedule of Members
Schedule 2 – Prohibited Competitors
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AMENDED AND RESTATED
LIMITED LIABILITY COMPANY AGREEMENT
This AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT (this “Agreement”) of Midwest Transmission Holdings, LLC (the “Company”) is made and entered into as of June 5, 2025 (the “Effective Date”), by and among the Company, AEP Transmission Company, LLC, a Delaware limited liability company (the “AEP Member”), and Olympus BidCo L.P., a Delaware limited partnership (the “Investor Member”). The Company, the AEP Member and the Investor Member are each sometimes referred to herein as a “Party” and, together, as the “Parties”.
RECITALS
1.    Immediately prior to the execution and delivery hereof, the AEP Member was the owner of 100% of the Membership Interests.
2.    On January 9, 2025, the Company, the AEP Member and the Investor Member entered into the Contribution Agreement, pursuant to which the Company has concurrently with the execution and delivery of this Agreement issued to the Investor Member Membership Interests constituting a 19.9% Percentage Interest.
3.    Upon the execution and delivery hereof, and in connection with the closing of the transactions contemplated by the Contribution Agreement, the AEP Member is the owner of Membership Interests constituting an 80.1% Percentage Interest, and the Members collectively are the owners of 100% of the Membership Interests.
4.    The Parties desire to, and by the execution and delivery of this Agreement hereby do, amend and restate in its entirety the Limited Liability Company Agreement of the Company, dated as of December 30, 2024, to provide for, among other things, the admission of the Investor Member as a Member, the rights and responsibilities of the Parties with respect to the governance, financing and operation of the Company and certain other matters relating to the business arrangements between the Parties with respect to the Company.
Therefore, in consideration of the mutual covenants and agreements contained in this Agreement and other good and valid consideration the receipt of which is hereby acknowledged by each Party, and intending to be legally bound hereby, the Parties hereby agree as follows:
ARTICLE I
GENERAL MATTERS
Section 1.1    Formation. The AEP Member formed the Company as a limited liability company pursuant to the Act. The Members ratify the organization, formation and continuation of the Company pursuant to the terms and conditions of this Agreement.
Section 1.2    Name. The name of the Company is “Midwest Transmission Holdings, LLC”.
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Section 1.3    Purpose.
(a)    The purpose of the Company is to, either on its own behalf or through its Subsidiaries, engage in all lawful business for which limited liability companies may be formed under the Act in furtherance of the following activities (the “Company Business”):
(i)    owning and operating public utilities engaged in the development, construction, commercialization, operation, maintenance or ownership of electric transmission assets and facilities located in the Target States, and such additional geographic regions as the Board may approve (subject to Article VIII);
(ii)    undertaking any business activities conducted as of the Effective Date by the Company or its Subsidiaries;
(iii)    engaging in such other related activities that are expected to be eligible to earn recovery through transmission rates approved or accepted by FERC; and
(iv)    engaging in such other activities as the Board deems necessary, convenient or incidental to the conduct, promotion or attainment of the activities described in the foregoing sub-clauses (i), (ii) and (iii).
(b)    The Company shall not engage in any activity or conduct inconsistent with the Company Business or any reasonable extensions thereof.
Section 1.4    Registered Office. The address of the registered office of the Company in the State of Delaware is Corporation Trust Center, 1209 Orange Street, Wilmington, New Castle County, Delaware 19801.
Section 1.5    Registered Agent. The name and address of the registered agent of the Company for service of process on the Company in the State of Delaware is The Corporation Trust Company, Corporation Trust Center, 1209 Orange Street, Wilmington, New Castle County, Delaware 19801.
Section 1.6    Members.
(a)    Each of the AEP Member and the Investor Member is hereby or was heretofore admitted to the Company as a Member, and hereby continues as such. Unless admitted to the Company as a Member as provided in this Agreement, no Person shall be, in fact or for any other purpose, a Member.
(b)    No Member shall have any right to withdraw from the Company except as expressly set forth herein. No Membership Interest is redeemable or repurchasable by the Company at the option of a Member. Except as expressly set forth in this Agreement, no event affecting a Member (including dissolution, bankruptcy or insolvency) shall affect its obligations under this Agreement or affect the Company.
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(c)    The Members’ names, addresses and Percentage Interests are set forth on the Schedule of Members attached to this Agreement as Schedule 1.
(d)    No Member, acting in its capacity as a Member, shall be entitled to vote on any matter relating to the Company other than as specifically required by the Act or as expressly set forth in this Agreement.
(e)    Except as otherwise expressly set forth in this Agreement, any matter requiring the action, consent, vote or other approval of the Members hereunder shall require action, consent, vote or approval of the Members owning at least a majority of the Membership Interests.
(f)    A Member shall automatically cease to be a Member upon direct Transfer of all of such Member’s Membership Interests made pursuant to and in accordance with the terms of this Agreement. Immediately upon any such permissible direct Transfer, the Company shall cause such Member to be removed from Schedule 1 to this Agreement and to be substituted by the transferee or transferees in such Transfer, and, except as otherwise expressly provided for herein, such transferee or transferees shall be deemed to be a “Member” and a “Party” for all purposes hereunder and all references to the AEP Member or the Investor Member, as the case may be, shall be deemed to be references to such transferee or transferees (notwithstanding, in the case that more than one Person is a transferee of such Membership Interests, that such defined terms as used herein are singular in number). All Membership Interests held or acquired by a Member and its Affiliates that from time to time hold Membership Interests shall be aggregated together for purposes of determining the rights or obligations of a Member, or application of any restrictions to a Member, or reference to its Membership Interests under this Agreement, in each instance in which such right, obligation or restriction is determined by any ownership threshold. In the event there is more than one Investor Member and such Members are not Affiliated, the appointment, consent and approval rights afforded hereunder to the Investor Member specifically (as opposed to any such rights afforded to Members generally) shall be exercised by the vote or consent of (i) with respect to any such rights expressly subject to any applicable Percentage Interest threshold or expressly applicable to any Investor Member regardless of Percentage Interest (including the Investor Member rights set forth in Section 2.2, Section 2.13, Section 8.1, Section 8.2, Section 8.3 and Section 13.15), each such Investor Member (together with its Affiliates), separately and independently, that meets any such applicable Percentage Interest threshold or (ii) with respect to any other such rights (including the Investor Member rights set forth in Section 6.3), by Investor Members holding a majority of the cumulative Membership Interests that are held by all of the Investor Members.
Section 1.7    Powers. The Company shall have the power and authority to do any and all acts necessary or convenient to or in furtherance of the purposes described in Section 1.3, including all power and authority, statutory or otherwise, possessed by, or which may be conferred upon, limited liability companies under the Laws of the State of Delaware.
Section 1.8 Limited Liability Company Agreement. This Agreement shall constitute the “limited liability company agreement” of the Company for the purposes of the Act. The rights, powers, duties, obligations and liabilities of the Members shall be determined pursuant to the Act and this Agreement.
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To the extent that the rights, powers, duties, obligations and liabilities of any Member are different by reason of any provision of this Agreement than they would be under the Act in the absence of such provision, this Agreement shall control to the fullest extent permitted by the Act and other applicable Law.
Section 1.9    Issuance of Additional Membership Interests. Except for (a) the issuance of any Excluded Membership Interests or (b) the issuance of Membership Interests made pursuant to and in accordance with Section 5.1, Article VII or as otherwise permitted herein, the Company shall not issue any new Membership Interests, or any securities convertible into Membership Interests or other equity interests of the Company, to any Third Party or to the Members other than in accordance with their respective Percentage Interests.
Section 1.10    No State Law Partnership. The Parties intend that the Company not be a partnership (including a limited partnership) or joint venture, and that no Member be a partner or joint venturer of any other Member by virtue of this Agreement, for any purposes, and neither this Agreement nor any other document entered into by the Company or any Member relating to the subject matter hereof shall be construed to suggest otherwise. Nothing in this Section 1.10 shall control with respect to income tax treatment of the Company.
ARTICLE II
MANAGEMENT
Section 2.1    Managers. Subject to the provisions of the Act and any limitations in this Agreement as to action required to be authorized or approved by the Members (including any action that requires the consent of the Investor Member pursuant to Section 8.1 or Section 8.2), the business and affairs of the Company shall be managed and all its powers shall be exercised by or under the direction of a board of Managers (the “Board” and each duly appointed and continuing member thereof from time to time, a “Manager”), and no Member, by virtue of having the status of a Member, shall have any management power over the business and affairs of the Company or any actual or apparent authority to enter into Contracts on behalf of, or to otherwise bind, the Company. Without prejudice to such general powers, but subject to the same limitations, the Board shall be empowered to conduct, manage and control the business and affairs of the Company and to make such rules and regulations therefor not inconsistent with applicable Law or this Agreement, as the Board shall deem to be in the best interest of the Company (subject to the limitations on fiduciary duties set forth in Section 2.11).
Section 2.2    Number of Managers; Proportional Appointment Rights.
(a)    The authorized number of Managers constituting the Board shall be 11 Managers, subject to any increase effected pursuant to Section 2.2(e) (the “Total Number of Managers”).
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(b) The Investor Member shall, as of the Effective Date, be entitled to appoint two Managers. The Investor Member shall retain the right to appoint two Managers for so long as it (together with its Affiliates) holds a Percentage Interest equal to or greater than 17.5%. In the event that the Investor Member’s Percentage Interest (together with its Affiliates) is reduced below 17.5% but remains at or above a 9.9% Percentage Interest, the Investor Member shall retain the right to appoint one Manager. In the event that the Investor Member’s Percentage Interest (together with its Affiliates) is reduced below 9.9%, the Investor Member shall cease to be entitled to appoint any Investor Managers. Managers appointed by the Investor Member are referred to herein as “Investor Managers”. The appointment of any particular proposed Investor Manager shall be subject to the AEP Member’s prior written consent of the identity of such individual prior to his or her appointment to the Board (such consent not to be unreasonably withheld, delayed or conditioned); provided, further, that the AEP Member shall not have any such consent right over the appointment of any proposed Investor Manager that is a Qualified Designee.
(c)    In the event that the Investor Member’s Percentage Interest decreases such that the Investor Member would be entitled to appoint a number of Investor Managers that is less than the number of Investor Managers then serving on the Board, the Investor Member will, concurrently with such decrease, designate (in the Investor Member’s sole discretion) one or more Investor Managers for removal from the Board, such that the number of Investor Managers serving on the Board is equal to the number of Investor Managers that the Investor Member is entitled to appoint at such time pursuant to Section 2.2(b), such removal or removals being effective immediately upon such designation. If the Investor Member fails to so designate Investor Managers concurrently with such decrease in the Investor Member’s Percentage Interest, then the AEP Member may designate (in the AEP Member’s sole discretion) for removal the number of Investor Managers required to be removed from the Board pursuant to the immediately foregoing sentence, such removal or removals being effective immediately upon such designation.
(d)    The AEP Member shall be entitled to appoint all of the remaining Total Number of Managers that the Investor Member is not entitled to appoint pursuant to Section 2.2(b). Managers appointed by the AEP Member are referred to herein as “AEP Managers”; provided, that any AEP Manager must be a Qualified Designee. The AEP Member shall further be entitled to designate an AEP Manager to serve as the chairperson of the Board.
(e) In the event that the Investor Member’s Percentage Interest increases such that the Investor Member would be entitled to appoint a number of Investor Managers that is greater than the number of Investor Managers then serving on the Board, the AEP Member will, concurrently with such increase, elect (such election to be made in the AEP Member’s sole discretion) to either (i) designate (in the AEP Member’s sole discretion) one or more AEP Managers for removal from the Board, such that the number of Manager positions available for Investor Managers is equal to the number of Investor Managers that the Investor Member is entitled to appoint at such time pursuant to Section 2.2(b), such removal or removals being effective immediately upon such designation, or (ii) increase the Total Number of Managers to create a number of new vacancies on the Board such that the number of Manager positions available for Investor Managers is equal to the number of Investor Managers that the Investor Member is entitled to appoint at such time pursuant to Section 2.2(b). If the AEP Member fails to so act concurrently with such increase in the Investor Member’s Percentage Interest, then the Investor Member may designate (in the Investor Member’s sole discretion) for removal the number of AEP Managers required to be removed from the Board had the AEP Member elected the actions set forth in clause (i) of the immediately foregoing sentence, such removal or removals being effective immediately upon such designation.
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(f)    For each Investor Manager that the Investor Member is entitled to appoint, the Investor Member shall be further entitled to identify up to an equal number of individuals (not to exceed the number of Investor Managers the Investor Member is then-entitled to appoint) (each, a “Designated Alternate”) who are authorized to attend meetings of the Board (or meetings of Board committees) in lieu of any Investor Manager in the event that such Investor Manager is unable to attend such meeting. A Designated Alternate will be entitled to exercise the powers of the applicable absent Investor Manager at such meetings, and will be subject to all of the responsibilities of an Investor Manager hereunder at such meeting as if they were the Investor Manager. The appointment of any Designated Alternate shall be subject to the same approval right of the AEP Member applicable to Investor Managers under Section 2.2(b). If a Designated Alternate is serving in lieu of an absent Investor Manager at any Board or committee meeting, the Investor Member shall provide notice to the AEP Member of this fact prior to the commencement of such meeting (which notice may be in the form of written notice, including by way of an email to the AEP Managers, or an oral announcement by the Designated Alternate of such fact at the commencement of such meeting), and such notice shall be recorded in the minutes of such meeting. For the avoidance of doubt, (i) the applicable Investor Manager for which a Designated Alternate was so designated, on the one hand, and such Designated Alternate, on the other hand, may not both function as a Manager at any meeting of the Board (or committee thereof), and (ii) any references to approval or notice by the Investor Managers in this Agreement will be deemed to refer to the Investor Managers, and not a Designated Alternate, except in respect of the voting on matters presented at the meeting at which a Designated Alternate is attending. In the event that the Designated Alternate is also the Board Observer, at any Board or committee meeting in which he or she is serving as an Investor Manager pursuant to this Section 2.2(f), he or she shall be deemed to be serving only as an Investor Manager and not as the Board Observer at such meeting.
Section 2.3 Removal of Managers. Any one or more Managers may be removed at any time, with or without cause, by the Member that appointed such Manager, and except as provided in Section 2.2(c) and Section 2.2(e), may not be removed by any other means. If a Manager is convicted by a court or equivalent tribunal of any felony (or equivalent crime in the applicable jurisdiction), or of any misdemeanor (or equivalent crime in the applicable jurisdiction) that involves financial dishonesty or moral turpitude, then the Member that appointed such Manager shall, unless consented to by the other Member, promptly remove such Manager. If a Manager is no longer a Qualified Designee, the Member that appointed such Manager shall promptly remove such Manager, unless consented to by each other Member that is not an Affiliate of the Member that appointed such Manager. Delivery of a written notice to the Company by a Member designating for removal a Manager appointed by such Member shall conclusively and with immediate effect constitute the removal of such Manager, without the necessity of further action by the Company, the Board, or by the applicable removed Manager. Each Manager duly appointed by a Member pursuant to and in accordance with the provisions of Section 2.2 shall hold office until his or her resignation, death, permanent disability, removal pursuant to and in accordance with Section 2.2 or with this Section 2.3, or until a successor Manager is duly appointed by the Member that appointed (and continues to be entitled to appoint) such Manager.
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Section 2.4    Vacancies. A vacancy shall be deemed to exist in case of the resignation, death, permanent disability or removal of any Manager, or pursuant to an increase in the Total Number of Managers pursuant to and in accordance with the provisions of Section 2.2(e). The Member entitled to appoint a Manager to the vacant Manager position may appoint or elect a Manager thereto to take office (a) immediately, (b) effective upon the departure of the vacating Manager, in the case of a resignation, or (c) at such other later time as may be determined by such Member.
Section 2.5    Acts of the Board; Voting. Except as otherwise expressly set forth in this Agreement (including Section 8.1 and Section 8.2), a vote of a majority of the Managers present at a duly called and noticed meeting of the Board at which a quorum is present shall be required to authorize or approve any action of the Board; provided, that if any Manager is not present at a meeting at which a quorum is established, the present Managers appointed by the same Member (or its Affiliates) as the absent Manager shall collectively have the right to cast one additional vote for each such Manager appointed by the same Member (or its Affiliates) not in attendance at such meeting that would be eligible to vote on the applicable action or decision if present at the meeting. Every act of or decision taken or made by the Managers pursuant to the vote required by this Section 2.5 shall be conclusively regarded as an act of the Board.
Section 2.6    Compensation of Managers. No compensation shall be paid to any Manager without the unanimous approval of the Board, provided that the allocated share of any such compensation shall reasonably be expected to be recoverable in the FERC-jurisdictional regulated rates for the transmission facilities owned by the Company Group. The Board shall also have the authority (but not the obligation) to reimburse Managers for expenses incurred for attendance at meetings of the Board or otherwise in connection with their respective service on the Board. Nothing herein shall be construed to preclude any Manager from serving the Company in any other capacity and receiving compensation therefor. If approved by the Board, the Board Observer may be entitled to reimbursement for expenses incurred for attendance at meetings of the Board to the same extent as if he or she were a Manager.
Section 2.7 Meetings of Managers; Notice. Except as provided pursuant to Section 2.10, meetings of the Board, both regular and special, for any purpose or purposes may be called at any time by the Board or by the Company at the request of any Manager, by providing at least seven calendar days’ written notice to each Manager unless the chairperson of the Board determines, acting reasonably, that there is a significant and time sensitive matter that requires shorter notice to be given, in which case a meeting of the Board may be called by giving at least 48 hours’ written notice to each Manager. Regular Board meetings will be held at least quarterly. Each notice shall state the purpose(s) of and agenda for the meeting and include all required information, including dial-in numbers or other applicable access information, in order to participate in the meeting by telephonic means, over the internet or by means of any other customary electronic communications equipment. Unless otherwise agreed by unanimous consent of the Board, no proposal shall be put to a vote of the Board unless it has been listed on the agenda for such meeting.
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Notice of the time and place of meetings shall be delivered personally or by telephone to each Manager, or sent by e-mail or other electronic communication to any Manager. Any notice given personally or by telephone shall be communicated to the applicable Manager. A Manager may waive the notice requirement set forth in this Section 2.7 by any means reasonable in the circumstances, including by communication to one or more other Managers, and the presence of a Manager at a meeting or the approval by a Manager of the minutes thereof shall conclusively constitute a waiver by such Manager of such notice requirement.
Section 2.8    Quorum.
(a)    Except as otherwise expressly set forth herein, the presence (whether physical, telephonic, over the internet or by means of other customary electronic communications equipment) of a majority of the number of Managers then serving on the Board (without regard to the Total Number of Managers) at a meeting of the Board, which must include at least one Investor Manager (if one is serving on the Board) and the number of AEP Managers necessary for the AEP Managers to constitute a majority of Managers at any such meeting, shall constitute a quorum of the Board for the transaction of all business thereat; provided, that if a quorum fails at two consecutive attempted meetings that are called pertaining to the same subject matter with proper notice due to the failure of the Investor Manager(s) to attend, then at the third attempted meeting only a majority of the number of Managers then serving on the Board, including the number of AEP Managers necessary for the AEP Managers to constitute a majority of Managers at any such meeting (without regard to the Total Number of Managers or the attendance of the Investor Manager(s)) must be present in person, by telephone or other electronic means or by proxy in order to constitute a quorum for the transaction of business for purposes of conducting only those matters that were included on the agenda for the attempted meetings immediately preceding such third attempted meeting.
(b)    If a quorum is not present at any meeting of the Board, the Managers present at such meeting may adjourn the meeting, without notice other than announcement at the meeting, and the Board or Manager that called for the meeting may attempt to reschedule such meeting until a quorum is present.
Section 2.9    Place and Method of Meetings.
(a) Meetings of the Board may be held at any place, whether within or outside the State of Delaware or the State of Ohio, and meetings may be held, in whole or in part, by telephonic means, over the internet or by means of any other customary electronic communications equipment. The place at which (or, if applicable, the electronic communication methods by which) a meeting will be held may be specified in the applicable notice of the meeting; provided, that in the absence of such specification, or in the event that any Manager objects to the place or electronic communication methods (if any) specified in the applicable notice, then the applicable meeting shall be held solely in physical presence at the principal executive office of the Company located at 1 Riverside Plaza, Columbus, OH 43215, as such location may change from time to time, it being understood that a Manager may participate in the applicable meeting in accordance with Section 2.9(b).
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(b)    The Managers may participate in meetings of the Board by telephonic means, over the internet or by means of any other customary electronic communications equipment, and, to the fullest extent permitted by applicable Law, shall be deemed to be present at such meeting for all purposes, including for purposes of determining quorum and of voting.
Section 2.10    Action by the Board Without a Meeting. Any action required or permitted to be taken by the Board may be taken without a meeting if a majority of the number of Managers then serving on the Board (or, if greater, the number of Managers the vote of whom would be minimally necessary to approve such action at a meeting of the Board) shall individually or collectively consent in writing to such action; provided, however, that, if (a) one or more Investor Managers are serving on the Board at the time of such written action, (b) the subject matter of such written action had not previously been addressed during a duly called and noticed meeting of the Board at which a quorum was present, and (c) no Investor Manager joins such written action, then, in such case, the written action shall not be effective until 48 hours after the secretary, assistant secretary or other officer of the Company designated by the Board has notified all then-serving Investor Managers of such action, it being understood that, during such 48-hour period, any Investor Manager shall be entitled to call a special meeting of the Board (to be held within such period and solely telephonically, over the internet or by means of other customary electronic communications equipment) for purposes of discussing with the Board the subject matter of such written action (without regard, solely for purpose of such discussion and not for purposes of taking any action that requires the vote of the Board, to whether a quorum is present to constitute a duly convened meeting of the Board). Notwithstanding the foregoing, no action set forth in Section 8.1 or Section 8.2 that requires the consent of the Investor Member shall be effected by written action entered into pursuant to this Section 2.10 without the Investor Member’s consent. Any written actions of the Board may be in counterparts and transmitted by e-mail and shall be filed with the minutes of the proceedings of the Board. Such written actions shall have the same force and effect as a vote of the Board.
Section 2.11    Duties of Managers. Each member of the Board shall have fiduciary duties identical to those of directors of a business corporation organized under the General Corporation Law of the State of Delaware; provided, however, that the Members expressly acknowledge and agree that the enforcement or exercise by an Investor Member (or an Investor Manager providing consent on behalf of an Investor Member pursuant to Section 8.4) of any of its rights under Section 8.1 or Section 8.2 and that the pursuit of business ventures by any Member as permitted by Section 9.3 shall in no event constitute a violation of the fiduciary duties of the applicable Investor Manager or Investor Member, which are hereby disclaimed in all respects with respect thereto. The provisions of this Agreement, to the extent that they expand or restrict the duties and liabilities of the Board, otherwise existing at law or in equity, are agreed by the Members to replace such other duties and liabilities of the Board.
Section 2.12 Committees. The Board may create one or more committees of the Board, delegate responsibilities, duties and powers to such one or more committees, and appoint Managers to serve thereon; provided, that, for so long as the Investor Member is entitled to appoint at least one Investor Manager, at least one Investor Manager shall be entitled to be a member of any such committee(s).
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Each Manager appointed to serve on any such committee shall serve at the pleasure of the Board, or otherwise in accordance with the terms of the resolution designating the applicable committee. Section 2.4, Section 2.7, Section 2.8, Section 2.9 and Section 2.10 shall each apply to any committee of the Board with the same terms applicable to the Board, mutatis mutandis.
Section 2.13 Investor Member Board Observer. An Investor Member shall be entitled to appoint one Person (which shall be an individual) to serve as an observer of the Board (the “Board Observer”) for so long as such Investor Member’s Percentage Interest is equal to or greater than 4.9% (but in no event shall there be more than one Board Observer and, if more than one Investor Member holds a Percentage Interest equal to or greater than 4.9%, the Board Observer shall be the Person designated in writing by a majority in interest of Investor Members holding a Percentage Interest equal to or greater than 4.9%), which such individual shall be a Representative of an Investor Member and the identity of whom shall be subject to the prior written consent of the AEP Member (such consent not to be unreasonably withheld, delayed or conditioned); provided, that the AEP Member shall not have any such consent right over the appointment of any proposed Board Observer that is a Qualified Designee. The Board Observer shall have the right to receive notice of, attend and participate in all meetings of the Board (and any committee thereof) and to receive all information provided to Managers at the same time and in the same manner as provided to such Managers; provided, however, that the Company and the Board will be entitled to withhold access to any portion of the information and to exclude the Board Observer from any portion of any meeting of the Board (or any committee thereof) if the Company or the Board determines in good faith in reliance upon the advice of counsel that access to such information or attendance at such meeting is reasonably necessary to preserve an attorney-client privilege of the Company or the Board; provided, however, that the Investor Member shall be notified of any intent to exclude the Board Observer in reliance on the foregoing proviso in advance of any meeting from which the Board Observer is to be excluded; provided, further, that, any Board Observer that is excluded shall only be excluded for such portion of the meeting during which such matter or transaction is being discussed. For the avoidance of doubt, the Board Observer shall not have any voting rights with respect to any matter brought before the Board and shall not be counted in any manner with respect to whether a quorum is present at a meeting of the Board, and (without limiting the Company’s obligations to provide the Board Observer with notice of meetings of the Board and any committee thereof as set forth in this Section 2.13) no defect in the provision of notice to the Board Observer of any meeting of the Board shall be construed to constitute a defect in the provision of notice to Managers. In the event that the Board Observer is also a Designated Alternate and, in such capacity, he or she is serving at a Board or committee meeting as an Investor Manager pursuant to Section 2.2(f), the Investor Member shall not be entitled to appoint an additional individual to serve as a replacement Board Observer to exercise the rights and duties of a Board Observer for that meeting. The Board Observer shall be bound by the same confidentiality obligations as the Managers as set forth in Section 9.4. The Investor Member may cause the Board Observer to resign or appoint a replacement Board Observer from time to time by giving written notice to the Company and shall, unless, consented to by the AEP Member, appoint a new Board Observer if the Board Observer ceases to be a Qualified Designee.
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In the event that the Investor Members are no longer eligible to appoint the Board Observer pursuant to the first sentence of this Section 2.13, the Investor Members’ rights under this Section 2.13 shall immediately cease. For the avoidance of doubt, the sole purpose of this Section 2.13 is to provide observation rights (subject to the limitations and conditions set forth in this Section 2.13) to an individual Representative of the Investor Member, and in no event will any Board Observer be construed to be a third-party beneficiary of this Agreement, an agent of the Company of any kind or for any purpose, or have any other claim against the Company or the Members in relation to any matter whatsoever.
Section 2.14    Related Party Matters.
(a)    All Contracts, arrangements and transactions (including corporate allocations and related methodologies), as well as Indebtedness (including in respect of the regulated money pool program of the AEP Outside Group) between any member of the AEP Outside Group, on the one hand, and the Company Group, on the other hand (such transactions, “Affiliate Transactions”), shall be (i) entered into and carried out in a manner that, except as may be required by any applicable Law or Order, is (A) consistent with past practices and the corporate allocation and affiliate transaction policies of the AEP Outside Group and the Company Group in effect at such time applied in a non-discriminatory manner in respect of the Company Group as compared to the members of the AEP Outside Group and (B) on terms and conditions that are commercially reasonable with respect to the subject matter thereof (it being understood that transactions undertaken pursuant to the corporate allocation policies and intercompany service agreements of the AEP Outside Group as of such time to the extent that they are non-discriminatory against the Company Group shall be deemed to be commercially reasonable), (ii) entered into and carried out in accordance with the requirements of any applicable Law or Order (including, for the avoidance of doubt, on such terms and conditions as may be required to obtain the approval of the applicable Governmental Body in respect of such transaction) and (iii) if the consent of the Investor Member is required pursuant to Section 8.1 or Section 8.2, subject to the prior written consent of the Investor Member. Notwithstanding anything to the contrary in this Agreement, except as required by applicable Law, the Board and the AEP Member and its Affiliates shall ensure at all times during the term of this Agreement that any methodologies used to allocate costs to the Company Group would not result in any fines, claims or penalties (including any settlement amounts) that are imposed on any member of the AEP Outside Group being allocated to the Company or any of its Subsidiaries other than fines, claims or penalties (including settlement amounts) imposed on a member of the AEP Outside Group that directly relate to services performed for or on behalf of, or that directly result from the business or operations of, a member of the Company Group. The AEP Member shall use commercially reasonable efforts to ensure the corporate separateness of the Company Group from the AEP Member and other members of the AEP Outside Group in a manner consistent with the Company Group’s and the AEP Outside Groups’ respective past practices and all applicable Laws and Orders.
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(b) The Investor Member acknowledges and agrees that (i) the Company Group and the AEP Outside Group have prior to the Effective Date engaged in Affiliate Transactions, and will, pursuant to and in accordance with the provisions of Section 2.14(a), from and after the Effective Date engage in Affiliate Transactions, subject to the Investor Member’s approval rights under Section 8.1 and Section 8.2 (if applicable to any such Affiliate Transactions), (ii) subject to Section 2.14(a) and Investor Member’s approval rights under Section 8.1 and Section 8.2 (if applicable), all services provided by any member of the AEP Outside Group to any member of the Company Group as of the Effective Date will continue in the ordinary course of business, and (iii) subject to Section 2.14(a) and the Investor Member’s approval rights under Section 8.1 and Section 8.2, the Company Group will (A) incur Indebtedness from members of the AEP Outside Group (I) on economic terms consistent with the economic terms of Indebtedness incurred by the AEP Outside Group with Third Parties (or in any case, no less favorable to the Company Group than the terms provided to the AEP Outside Group by such Third Parties with respect to such Indebtedness) or (II) in accordance with the regulated money pool program of the AEP Outside Group, and in each case the terms of such Indebtedness shall be deemed to be commercially reasonable and (B) if and when approved by the Board, make repayments (including voluntary repayments) of any Indebtedness from members of the AEP Outside Group including the AEP TransCo Note.
(c) In the event the Company, its Subsidiaries and/or the AEP Member becomes aware of any material breach or material default (it being understood that, for purposes of this clause (c), a breach or default will be deemed to be “material” if (x) the reasonably expected amount of damages that would be sustained by the Company and its Affiliates as a result of such breach or default, or series of related breaches or defaults, would exceed $30,000,000 individually or in the aggregate or (y) the breach or default would otherwise be material to the Company Group, taken as a whole) by any member of the Company Group or AEP Outside Group under any Affiliate Transaction (an “Affiliate Transaction Default”), the Company and/or the AEP Member, as applicable, shall promptly, but in any event within 10 Business Days after becoming aware of such Affiliate Transaction Default, send a written notice (a “Default Notice”) to the Company and the Investor Member setting forth in reasonable detail the nature of such Affiliate Transaction Default and the reasonable estimate of the current and future anticipated losses associated with such Affiliate Transaction Default (to the extent feasible to make a reasonable estimate at such time). After delivery of such Default Notice to the Investor Member, the Company (and, if the Company did not provide the Default Notice, the AEP Member) shall promptly provide the Investor Member with any additional information reasonably requested by the Investor Member relating to such Affiliate Transaction Default. The defaulting party under such Affiliate Transaction shall have (i) 10 Business Days following the expiration of the applicable cure period in respect of such Affiliate Transaction, to fully cure any monetary Affiliate Transaction Default, and (ii) 60 days following the expiration of the applicable cure period in respect of such Affiliate Transaction, to fully cure any non-monetary Affiliate Transaction Default, subject to and consistent with applicable Law and Orders. In the event that any material alleged Affiliate Transaction Default is not timely cured in accordance with the preceding sentence, the Investor Member shall have the sole right to cause the Company Group to take, or refrain from taking, any actions in connection with the enforcement of or compliance with the rights or obligations of the Company or any of its Subsidiaries under the terms of the applicable Affiliate Transaction, including the commencement of any litigation, proceeding or other action on behalf of the Company or any of its Subsidiaries against the applicable member(s) of the AEP Outside Group.
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(d)    The Company shall notify the Investor Member prior to, or within 10 Business Days following, its or any of its Subsidiaries’ execution of any new Affiliate Transaction material to the Company Group or any amendment to any Affiliate Transaction that is material to the Company Group, in each case, to the extent the allocated share of such Affiliate Transaction involves revenues or expenditures that are not reasonably expected to be, recoverable in the FERC-jurisdictional rates for the transmission facilities owned by the Company Group, which notice shall set forth in reasonable detail the nature of such new Affiliate Transaction or such amendment and, upon request from the Investor Member, shall provide copies of all Contracts relating to such new Affiliate Transaction or such amendment within five Business Days of such request.
Section 2.15    D&O Insurance. The Company shall maintain (or AEP Member shall, or shall cause its Affiliates to, maintain on behalf of the Company) directors’ and officers’ insurance coverage covering each Manager on the Board in customary and reasonable amounts for so long as at least one Manager is on the Board.
ARTICLE III
OFFICERS
Section 3.1    Appointment and Tenure.
(a)    The Board may, from time to time, designate officers of the Company to carry out the day-to-day business of the Company.
(b)    The officers of the Company shall be comprised of one or more individuals designated from time to time by the Board, subject to any applicable consultation right of Investor Member pursuant to Section 8.3(c). Each officer shall hold his or her office for such term and shall have such authority and exercise such powers and perform such duties as shall be determined from time to time by the Board. Any number of offices may be held by the same individual. The salaries or other compensation, if any, of the officers shall be fixed from time to time by the Managers.
(c)    The officers of the Company may consist of a president, a secretary and a treasurer. The Board may also designate one or more vice presidents, assistant secretaries and assistant treasurers. The Board may designate such other officers and assistant officers and agents as the Board may deem necessary or appropriate.
Section 3.2    Removal. Any officer may be removed as such at any time by the Board, either with or without cause, in its discretion.
Section 3.3 President. The president, if one is designated, shall be the chief executive officer of the Company, shall have general and active management of the day-to-day business and affairs of the Company as authorized from time to time by the Board, and shall be authorized and directed to implement all actions, resolutions, initiatives and business plans adopted by the Board.
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The president may sign and execute in the name of the Company, deeds, mortgages, bonds or Contracts except in cases where the signing and execution thereof shall be expressly delegated by the Board or by this Agreement to some other officer or agent of the Company or shall be required by Law otherwise to be signed or executed. The president may, by instrument in writing, delegate authority to any employee or Representative to sign and execute in the name of the Company deeds, mortgages, bonds or Contracts authorized by the Board except where the signing and execution of such documents shall be expressly delegated by the Board to some other officer or agent of the Company or shall be required by Law or otherwise to be signed or executed.
Section 3.4    Vice Presidents. The vice presidents, if any are designated, in the order of their election, unless otherwise determined by the Board, shall, in the absence or disability of the president, perform the duties and have the authority and exercise the powers of the president. They shall perform such other duties and have such other authority and powers as the Board may from time to time prescribe.
Section 3.5    Secretary; Assistant Secretaries. The secretary, if one is designated, shall perform such duties and have such powers as the Board may from time to time prescribe. The assistant secretaries, if any are designated, and unless otherwise determined by the Board, shall, in the absence or disability of the secretary, perform the duties and exercise the powers of the secretary. They shall perform such other duties and have such other powers as the Board may from time to time prescribe.
Section 3.6    Treasurer; Assistant Treasurers. The treasurer, if one is designated, shall have custody of the Company’s funds and securities and shall keep full and accurate accounts and records of receipts, disbursements and other transactions in books belonging to the Company, and shall deposit all moneys and other valuable effects in the name and to the credit of the Company in such depositories as may be designated from time to time by the Board. The treasurer shall disburse the funds of the Company as may be ordered by the Board, taking proper vouchers for such disbursements, and shall render the president and the Board, when so directed, an account of all of his or her transactions as treasurer and of the financial condition of the Company. The treasurer shall perform such other duties and have such other powers as the Board may from time to time prescribe. If required by the Board, the treasurer shall give the Company a bond of such type, character and amount as the Board may require. The assistant treasurers, if any are designated, unless otherwise determined by the Board, shall, in the absence or disability of the treasurer, perform the duties and exercise the powers of the treasurer. They shall perform such other duties and have such other powers as the Board may from time to time prescribe.
Section 3.7 Duties of Officers; Limitations of Authority. Each officer of the Company and its Subsidiaries (in such individual’s capacity as an officer) will owe the Company, its Subsidiaries and the Members such fiduciary duties that apply to officers of a Delaware corporation. No provision of this Agreement will be deemed to limit or eliminate such fiduciary duties.
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Notwithstanding anything to the contrary contained in this Article III, in no event shall any officer of the Company or any officer or director of any Subsidiary of the Company be permitted to take any action set forth in Section 8.1 or Section 8.2 that requires the consent of the Investor Member unless approved by the Investor Member in accordance with Section 8.1 or Section 8.2, as applicable.
ARTICLE IV
DEFAULT; DISSOLUTION
Section 4.1    Events of Default. The following shall constitute events of default (each, an “Event of Default”) by the applicable Member under this Agreement:
(a)    any material breach of this Agreement by such Member;
(b)    any failure by such Member to make any Additional Funding Requirement pursuant to and in accordance with a Capital Request Notice issued pursuant to Section 5.1 if such Member indicated it would do so in its written Response To Capital Call but then failed to do so within the time period specified in Section 5.1;
(c)    any failure by an Investor Member to maintain in full force and effect an ECL or any replacement Credit Support thereof provided in accordance with Section 6.3(d);
(d)    any purported Transfer by such Member made other than pursuant to and in accordance with the terms and conditions of this Agreement; and
(e)    the filing of a petition seeking relief, or the consent to the entry of a decree or Order for relief in an involuntary case, under the bankruptcy, rearrangement, reorganization or other debtor relief Laws of the United States or any state or any other competent jurisdiction or a general assignment for the benefit of its creditors by such Member or by any of its controlling Affiliates.
Section 4.2    Default Notice. If an Event of Default occurs, then any Member (other than the Member subject to the Event of Default (the “Defaulting Member”)) may deliver to the Company and to the Defaulting Member a written notice of the occurrence of such Event of Default, setting forth the circumstances of such Event of Default. The provisions of this Agreement applicable to a “Defaulting Member” shall apply to such Defaulting Member (a) with respect to Events of Default described in clauses (a), (b), (d) and (e) of Section 4.1, from and after the delivery of such written notice until the Event of Default and the material effects thereof have been cured (if capable of being so cured) and (b) with respect to Events of Default described in clause (c) of Section 4.1, from and after thirty (30) days following the delivery of such written notice unless and until the Event of Default and the material effects thereof have been cured.
Section 4.3    Dissolution.
(a) Subject to obtaining the requisite authorization, approval or consent of any Governmental Body, the Company shall dissolve, and its affairs shall be wound up, upon either (i) the approval by the Board and the written consent of all of the Members or (ii) the entry of a decree of judicial dissolution under Section 18-802 of the Act (each, an “Event of Dissolution”).
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(b)    Upon the occurrence of an Event of Dissolution, the Company will continue solely for the purposes of winding up its affairs in an orderly manner, liquidating its assets and satisfying the claims of its creditors and the Members. No Member, acting in its capacity as such, will take any action that is inconsistent with, or not necessary to or appropriate for, the winding up of the Company’s business and affairs. All covenants contained and obligations provided for in this Agreement will continue to be fully binding upon the Members until such time as the property of the Company has been distributed pursuant to Section 5.3 and the certificate of formation of the Company has been canceled pursuant to the Act.
(c)    After the occurrence of an Event of Dissolution, and after all of the Company’s debts, liabilities and obligations have been paid and discharged or adequate reserves have been made therefor and all of the remaining assets of the Company have been distributed to the Members, the Company shall make necessary resolutions and filings to dissolve the Company under the Act.
ARTICLE V
CAPITAL CONTRIBUTIONS; DISTRIBUTIONS
Section 5.1    Capital Contributions.
(a)    Subject to Section 8.1 and Section 8.2, if the Board determines that it is in the best interests of the Company to obtain additional equity capital for purposes of (i) developing, constructing, acquiring, operating or maintaining Qualifying Core Assets or funding ordinary course operations of the Company Business, (ii) satisfying the Company’s obligations in respect of the Company Group Third Party Indebtedness, (iii) complying with applicable Law or Order or (iv) funding any Emergency Expenditures (any such determination by the Board, an “Additional Funding Requirement”), then the Board may direct the Company to submit to the Members a written capital funding request notice (a “Capital Request Notice”), which Capital Request Notice shall set forth (A) the anticipated amount of, and the reason for, such Additional Funding Requirement, (B) each Member’s requested share of such Additional Funding Requirement, which with respect to each Member shall equal such Member’s Percentage Interest multiplied by the aggregate amount of the Additional Funding Requirement (such share, the “Pro Rata Request Amount”) and (C) the funding date for such Additional Funding Requirement (the “Capital Request Funding Date”), which Capital Request Funding Date shall not be earlier than 30 days (or, with respect to an Additional Funding Requirement solely to fund Emergency Expenditures, 20 days) following the date on which such Capital Request Notice is delivered to the Members. Subject to the express provisions of this Article V and the terms of Investor Member’s ECL, each Member may, but shall not be obligated to, contribute its Pro Rata Request Amount as called for in the applicable Capital Request Notice. Additional Funding Requirements will be considered a “Mandatory Capital Contribution” applicable to all Members to the extent Investor Member’s pro-rata share of such Additional Funding Requirement would not cause Investor Member to make capital contributions in excess of the Remaining Annual Maximum Commitment Amount as of the Capital Request Funding Date for such calendar year.
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Upon the receipt of a Capital Request Notice, each Member shall, within 20 days of such receipt, provide written notice to the Company and the other Members as to the extent to which such Member intends to fund its Pro Rata Request Amount, whether in whole, in part or not at all (a “Response To Capital Call”). If one Member indicates in its Response To Capital Call that it does not intend to fund its Pro Rata Request Amount in full, and any other Member had, prior thereto, submitted a Response To Capital Call indicating that it intends to fund a greater percentage than such other Member of its Pro Rata Request Amount, then such other Member will be entitled to amend its Response To Capital Call to reduce its percentage funding to an amount representing a percentage of its Pro Rata Request Amount not less than the lower percentage indicated in the other Member’s Response To Capital Call. For the avoidance of doubt and subject to the foregoing sentence (and the terms of the ECL), no Member shall have any obligation to fund any Additional Funding Requirement pursuant to this Section 5.1 unless such Member indicates that it will do so in its Response To Capital Call. Any Capital Request Notice or Response to Capital Call may be delivered by electronic mail to the electronic mail addresses specified in, or pursuant to, Section 13.1 without any copy to counsel specified therein.
(b)    If any Member refuses (including by indicating in its Response to Capital Call that it does not intend to fund its Pro Rata Request Amount in full) or fails to make all or any portion of its Pro Rata Request Amount pursuant to this Section 5.1 on or prior to the applicable Capital Request Funding Date (such Member, the “Non-Contributing Member”, and the unfunded amount, the “Unfunded Amount”), then the Company shall provide written notice thereof upon such refusal or such failure to the Members (the “Contribution Unfunded Amount Notice”), and:
(i)    Excess Contribution. To the extent that the Non-Contributing Member contributes a portion (but less than all) of its Pro Rata Request Amount, and another Member has contributed a greater percentage of its Pro Rata Request Amount than the Non-Contributing Member (the “Over-Contributing Member”), the Over-Contributing Member shall have the right to elect (which election shall be made by written notice to the Company and the other Members no later than 10 Business Days following the date of the Contribution Unfunded Amount Notice) to (A) receive a special distribution of the portion of the Pro Rata Request Amount contributed by the Over-Contributing Member associated with such excess percentage (the “Excess Contribution”), or any portion thereof, such that the Excess Contribution or applicable portion thereof is returned to the Over-Contributing Member (and the Company shall cause such special distribution to be made as promptly as practicable) and (B) have any remaining portion of such Excess Contribution (to the extent not distributed to the Over-Contributing Member in accordance with clause (i)(A) above) that would have been the Non-Contributing Member’s share thereof treated as a (I) loan to the Company (consistent with the methodology in clause (ii)(A) below), or (II), solely in the case the AEP Member is the Over-Contributing Member, contribution to capital (consistent with the methodology in clause (ii)(B) below) (or, solely in the case the AEP Member is the Over-Contributing Member, as any combination thereof as the AEP Member elects).
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(ii)    Top-Up Right. A Member that has paid its full Pro Rata Request Amount (the “Contributing Member”) shall have the right (but not the obligation) to elect (which election shall be made by written notice to the Company and the other Members no later than 10 Business Days following the receipt of the Contribution Unfunded Amount Notice) to contribute any portion of the Unfunded Amount in accordance with this Section 5.1(b) either (A) as a loan to the Company, or (B), solely in the case the AEP Member is the Contributing Member, as a capital contribution to the Company (or, solely in the case the AEP Member is the Contributing Member, as any combination thereof as the AEP Member elects) in accordance with the following procedures:
(A)    Loan. The Contributing Member may elect to advance all or a portion of the Unfunded Amount to the Company on behalf of the Non-Contributing Member, which advance shall be treated as a loan by the Contributing Member to the Non-Contributing Member (an “Unfunded Amount Loan”) at an interest rate equal to (i) solely to the extent the failure to fund the capital contributions was in respect of a Mandatory Capital Contribution, the greater of (I) the prime rate of interest per annum published in The Wall Street Journal under “Money Rates”, as such rate may be in effect from time to time, as of the date such amount was advanced plus 2% and (II) the highest rate payable on any Company Group Third Party Indebtedness and (ii) in all other cases the highest rate payable on any Company Group Third Party Indebtedness. Subject to the terms of this Agreement, each Unfunded Amount Loan shall be repaid out of any subsequent distributions made pursuant to Section 5.2 to which the Non-Contributing Member would otherwise be entitled under this Agreement, and such payments shall be applied first to the payment of accrued but unpaid interest on each such Unfunded Amount Loan and then to the payment of the outstanding principal until such Unfunded Amount Loan is paid in full.
(B) Capital Contribution. Except in the event that the Non-Contributing Member is the AEP Member, the AEP Member may elect to contribute an amount equal to all or a portion of the Unfunded Amount to the Company. If the AEP Member elects to contribute to the Company all or a portion of the Unfunded Amount, then, on or after the earlier of the date that the Non-Contributing Member indicates it will not cure the failure to fund its full Pro Rata Request Amount and the 30th day following the date of the Contribution Unfunded Amount Notice, the Company shall issue to the AEP Member the amount of additional Membership Interests that can be purchased for such funded amount at a price per Membership Interest equal to (i) solely to the extent the failure to fund the capital contributions was in respect of a Mandatory Capital Contribution, 90% of the Fair Market Value of the Company (measured as of immediately prior to the time that such contribution is to be made) per Membership Interest or (ii) in all other cases, the Fair Market Value of the Company (measured immediately prior to the time that such contribution is to be made) per Membership Interest, and the AEP Member’s and the Non-Contributing Member’s respective Percentage Interests will be adjusted accordingly.
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(C)    Cure Right. Notwithstanding anything to the contrary in this Section 5.1, on or before the 30th day following the date of the Contribution Unfunded Amount Notice, a Non-Contributing Member may make a contribution to the Company equal to the sum of the Unfunded Amount plus, if the Contributing Member already made an Unfunded Amount Loan in respect of such Unfunded Amount, any interest accrued on the Unfunded Amount Loan, following which (1) the Unfunded Amount advanced by the Contributing Member to the Company together with any such interest shall be paid to the Contributing Member, and (2) the former Non-Contributing Member shall be deemed to have cured its failure to pay the Pro Rata Request Amount prior to the Capital Request Funding Date with respect to the applicable Capital Request Notice.
(c) If the Non-Contributing Member refuses or fails to make its full Pro Rata Request Amount pursuant to this Section 5.1 on or prior to the applicable Capital Request Funding Date and the Contributing Member has not fully funded the Unfunded Amount in accordance with Section 5.1(b), then on or after the 30th day following the date of the applicable Contribution Unfunded Amount Notice, the Board may authorize the Company to seek additional equity funds on commercially reasonable terms from a Third Party in an amount up to the difference between the total Additional Funding Requirement requested and the total funds received by the Company from the Non-Contributing Member and the Contributing Member (including any additional funds that the Contributing Member may have contributed pursuant to Section 5.1(b)), and to issue Membership Interests to Third Parties in connection therewith pursuant to this Section 5.1(c). If the Board determines to seek additional equity funds from and issue Membership Interests to a Third Party pursuant to this Section 5.1(c), then the Company must consummate such issuance within 180 days following the Capital Request Funding Date. If such issuance is not consummated within such 180-day period, then the Company’s right to so issue Membership Interests to a Third Party in connection with the applicable Additional Funding Requirement shall be lapsed, and the Company shall not thereafter issue any Membership Interests to a Third Party in connection with such Additional Funding Requirement; provided that, if a definitive agreement providing for such issuance is executed prior to the expiration of such 180-day period but the issuance has not been consummated at the expiration of such period solely as a result of a failure to receive the requisite authorization, approval or consent of any Governmental Body in respect of such issuance, then such period shall be extended solely to the extent necessary to permit the receipt of all such authorizations, approvals or consents which are in process but have not been received from the relevant Governmental Body as of such original expiration date and the consummation of the issuance provided for in such definitive agreement; provided, further, that the Company shall have used its reasonable best efforts in seeking such authorizations, approvals and consents. Upon the completion of such issuance of Membership Interests pursuant to this Section 5.1(c), the Company shall give written notice to the Members of such issuance, which notice shall specify (i) the total number of new Membership Interests issued, (ii) the price per Membership Interest at which the Company issued the Membership Interests, (iii) any other material terms of the issuance and (iv) the resulting Percentage Interests of each Member.
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(d) In the event that the Investor Member refuses or fails to fund all or any portion of its share of an Additional Funding Requirement pursuant to this Section 5.1 on or prior to the applicable Capital Request Funding Date in respect of two Mandatory Capital Contributions, subject to Section 5.1(b)(ii)(C), from and after the occurrence of the second such refusal or failure by the Investor Member, the AEP Member may (but is not required to), at its option at any time during the 36-month period following the date of such second failure to fund by Investor Member (the “Call Period”), acquire all (but not less than all) of the Membership Interests held by the Investor Member (together with its Affiliates) (the “Call Right”) by giving written notice (the “Call Notice”) to the Investor Member of its election to exercise the Call Right; provided that the Investor Member shall have 60 days following the Call Notice to cure the most recent such failure to fund. If the AEP Member does not deliver the Call Notice to exercise its Call Right within the applicable Call Period, the Call Right shall expire solely with respect to the two failures to fund giving rise to such Call Right. The purchase price payable by the AEP Member in connection with the exercise of the Call Right shall be equal to the product of (i) 90% of the Fair Market Value of the Company (measured as of the date of the delivery of the Call Notice to the Investor Member) multiplied by (ii) a fraction, (A) the numerator of which is the number of Membership Interests that the Investor Member (together with its Affiliates) owns at such time and (B) the denominator of which is the total number of Membership Interests then outstanding (the amount equal to such product, the “Call Exercise Price”). If the Call Right is exercised by the AEP Member within the applicable Call Period, each of the Parties shall take all actions as may be reasonably necessary to consummate the transactions contemplated by this Section 5.1(d) as promptly as practicable, but in any event not later than 30 days after, or, if the Investor Member indicates its intent to cure its funding failure prior to such 30th day, 60 days after, the delivery of the Call Notice or, if authorizations, approvals or consents from a Governmental Body are required prior to such consummation, 15 days after the receipt of all such required authorizations, approvals or consents (such period, the “Call Consummation Period”), including entering into agreements, delivering applicable certificates and instruments and obtaining and cooperating to obtain any consents, in each case as may be deemed reasonably necessary. If the applicable Investor Member fails to take all actions necessary to consummate the Transfer of the Membership Interests held by it in accordance with this Section 5.1(d) prior to the expiration of the Call Consummation Period, then such Investor Member shall be deemed to be in material breach of this Agreement for purposes of Article IV and for all other purposes hereunder, and shall be deemed to have granted (and hereby grants, contingent only on the occurrence of such failure) an irrevocable appointment of any Person nominated for the purpose by the AEP Member to be such Investor Member’s agent and attorney to execute all necessary documentation and instruments on its behalf to Transfer the Investor Member’s Membership Interest to the Company as the holder thereof, in each case consistent with the provisions of this Section 5.1(d). At the consummation of any purchase and sale pursuant to this Section 5.1(d), the Investor Member shall sell to the AEP Member all of the Membership Interests owned by the Investor Member (together with its Affiliates) in exchange for the Call Exercise Price. Contemporaneously with its receipt from the AEP Member of the Call Exercise Price, the Investor Member (together with its Affiliates) shall Transfer to the AEP Member all of the Membership Interests owned by the Investor Member (together with its Affiliates), free and clear of all Liens other than those arising as a result of or under the terms of this Agreement and those arising under securities Laws of general applicability pertaining to limitations on the transfer of unregistered securities. The Members and the Company acknowledge and agree that they shall cooperate reasonably to obtain any necessary authorization, approval or consent of any Governmental Body to consummate the transactions contemplated by this Section 5.1(d). For the avoidance of doubt, in the event the Call Right is exercised, the Investor Member may request the Fair Market Value be determined in accordance with Section 13.15, regardless of the Investor Member’s Percentage Interest at such time.
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(e)    The Investor Member has delivered to the Company on the Effective Date the ECLs. Solely to the extent the Remaining ECL Annual Commitment Amount as of the Capital Request Funding Date is greater than zero, the Investor Member shall be required to make its portion of a Mandatory Capital Contribution. In the event the Investor Member fails to make its portion of any such Mandatory Capital Contribution to the extent the Remaining ECL Annual Commitment Amount as of the Capital Request Funding Date is greater than zero dollars, the Company shall be entitled to enforce the Investor Member’s obligation to fund solely up to such Remaining ECL Annual Commitment Amount, in addition to the other remedies provided herein (with the Investor Managers abstaining from determining any such enforcement). For the avoidance of doubt, (i) in no event shall the Company be entitled to enforce the Investor Member’s obligation to fund any such portion of Mandatory Capital Contribution to the extent it would cause the Investor Member to make capital contributions in excess of the ECL Annual Commitment Amount for the applicable calendar year and (ii) whether or not the Company enforces such obligation or enforces its rights as a third party beneficiary under the ECLs, if a capital contribution is made, such funding shall be treated as the funding of a capital contribution by the Investor Member for purposes of determining whether any remedies set forth in Section 5.1(b) are available.
Section 5.2    Distributions Generally; Support Payments.
(a)    Except as otherwise provided herein and subject to Section 5.2(b), Section 5.2(c) and the Act, no later than 60 days after the end of each fiscal quarter, the Company shall make distributions in cash of all its Available Cash in respect of such fiscal quarter. The Company may make such other more frequent distributions (including interim distributions) at such times and in such amounts as the Board may determine.
(b)    Except as otherwise provided herein, all distributions shall be paid to the Members only in cash and in the same proportion as their respective Percentage Interest; provided that, in the case of distributions to be paid in respect of any period during which the Percentage Interest of the Members changed following the Effective Date, such distributions shall be prorated to reflect the Percentage Interest of the Members on each day of such measurement period, and the Company and the Members shall take such action as necessary to effectuate such proration.
(c)    Notwithstanding the terms of this Section 5.2 and any other provision of this Agreement, (i) the Company shall not make any distribution to any Member on account of
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its Membership Interests to the extent such distribution would violate the Act, other applicable Law or an Order, and (ii) a Member may direct the payment of part or all of any distribution to another Person by providing written notice of such direction to the Company.
Section 5.3    Distributions upon the Occurrence of an Event of Dissolution. Upon the occurrence of an Event of Dissolution, the Board will proceed, subject to the provisions herein, to wind up the affairs of the Company, liquidate and distribute the remaining assets of the Company (provided, however, that all distributions shall be paid to the Members only in cash) and apply the proceeds of such liquidation in the order of priority in accordance with Section 18-804 of the Act or as may otherwise be agreed to by the Members.
Section 5.4    Withdrawal of Capital; Interest. Except as expressly provided in this Agreement, (a) no Member may withdraw capital or receive any distributions from the Company and (b) no interest shall be paid by the Company on any capital contribution or distribution.
ARTICLE VI
TRANSFERS OF MEMBERSHIP INTERESTS
Section 6.1    General Restriction.
(a)    No Member shall Transfer any of its Membership Interests except pursuant to and in accordance with this Article VI. Any purported Transfer by any Member of its Membership Interests in violation of this Section 6.1(a), or without compliance in all respects with the provisions of this Article VI pertaining to such purported Transfer, shall be invalid and void ab initio, and such purported Transfer by such Member shall constitute a material breach of this Agreement for purposes of Article IV.
(b)    Subject to Section 6.2 and Section 6.6, neither the Investor Member nor the AEP Member may Transfer any of its Membership Interests to any Person prior to the date that is the third anniversary of the Effective Date (the “Lock-Up Period”), other than with the prior written consent of the AEP Member or the Investor Member, as applicable. After the expiration of the Lock-Up Period, each of the Investor Member and the AEP Member, as applicable, may Transfer its Membership Interests in accordance with this Article VI.
Section 6.2    Transfers to Permitted Transferees; Liens by Members.
(a) Notwithstanding Section 6.1, each of the Members may Transfer at any time all or any portion of the Membership Interests held by it to any one of its Permitted Transferees; provided that, in connection with any such Transfer, (a) if such Transfer is a direct Transfer, such Permitted Transferee shall, in writing, assume all of the rights and obligations of the transferring Member as a Member under this Agreement and as a Party hereto with respect to the Transferred Membership Interests and (b) effective provision shall be made whereby such Permitted Transferee shall be required, prior to the time when it shall cease to be a Permitted Transferee of the transferring Member, to Transfer such Membership Interests to the transferring Member or to another Person that would be a Permitted Transferee of the transferring Member as of such applicable time. In the event that a Member (including, as the case may be, a Permitted Transferee) intends to Transfer its Membership Interests to a Permitted Transferee, such transferring Member or the Permitted Transferee, as applicable, shall notify the other Member and the Company of the intended Transfer at least 20 Business Days prior to the intended Transfer.
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(b)    Each Member shall be permitted to directly or indirectly Encumber its Membership Interests or any equity interests in such Member in connection with any debt financing, the proceeds of which have been or will be used by such Member to finance its purchase of such Membership Interests (whether in respect of an issuance of new Membership Interests by the Company or the purchase of existing Membership Interests from a Member), to directly or indirectly fund future or additional capital contributions, or in the refinancing of any such debt financing in the future, and neither such Lien nor any commencement or consummation of foreclosure proceedings or exercise of foreclosure remedies by a secured party on, or the subsequent direct or indirect sale of, a Member’s Membership Interests Encumbered in connection with any such debt financing shall, in either case, be considered a “Transfer” for any purpose under this Agreement; provided, that (i) such Member shall be obligated to promptly notify the other Member and the Company in writing following the commencement of any such foreclosure remedies or proceedings, (ii) in the event of the consummation of such a foreclosure, such Member will automatically cease to be deemed the owner of the Membership Interests so foreclosed and will cease to have any rights in respect thereof (with the financing source foreclosing on such Membership Interests succeeding to the rights and responsibilities of the Member hereunder), and (iii) the consummation of any such foreclosure will be subject to the receipt of any required authorization, approval or consent of all applicable Governmental Bodies.
Section 6.3    Right of First Offer.
(a)    Prior to any Transfer by a Member (each, a “Transferring Member”) of Membership Interests constituting 50% or less of the outstanding Membership Interests, other than to a Permitted Transferee of such Transferring Member or pursuant to Put Sales in accordance with Section 6.6, the Transferring Member must first offer to sell, or cause to be offered for sale, to the other Member (the “Non-Transferring Member”) all of the equity interests (corresponding to direct or indirect interests in the Membership Interests to be Transferred) that it desires to sell (such equity interests to be offered for sale to the Non-Transferring Member pursuant to this Section 6.3, the “Subject Membership Interests”), in each case, in accordance with the procedures set forth in the provisions of this Section 6.3. Notwithstanding anything to the contrary, a Non-Transferring Member may delegate its rights to purchase the Subject Membership Interests to a Person that would qualify as a Permitted Transferee, and the Transferring Member may delegate its rights to sell the Subject Membership Interests to the Persons owning such Subject Membership Interests (if not the Transferring Member itself), and the applicable rights and obligations afforded to such Member pursuant to this Section 6.3 shall apply to such delegee mutatis mutandis.
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(i) The Transferring Member shall first deliver to the Non-Transferring Member a written notice (a “Sale Notice”) setting forth the cash price and all of the other material terms and conditions at which the Transferring Member is willing to sell the Subject Membership Interests to the Non-Transferring Member, which notice shall constitute an offer to the Non-Transferring Member to effect such purchase and sale on the terms set forth therein. Any such Sale Notice shall be firm, not subject to withdrawal and prepared and delivered in good faith. Within 30 days following its receipt of a Sale Notice, the Non-Transferring Member may accept the Transferring Member’s offer and purchase the Subject Membership Interests at the cash price and upon the other material terms and conditions set forth in the Sale Notice, in which event the closing of the purchase and sale of the Subject Membership Interests will take place as promptly as practicable. The Sale Notice shall contain representations and warranties by the Transferring Member to the Non-Transferring Member that (A) the Transferring Member has full right, title and interest in and to the Subject Membership Interests, (B) the Transferring Member has all the necessary power and authority and has taken all necessary action to Transfer the Subject Membership Interests to the Non-Transferring Member as contemplated by this Section 6.3, and (C) the Subject Membership Interests are free and clear of any and all Liens other than those arising as a result of or under the terms of this Agreement and those arising under securities Laws of general applicability pertaining to limitations on the transfer of unregistered securities.
(ii) If the Non-Transferring Member does not accept the Transferring Member’s offer within such 30-day period, then the Transferring Member will, for a period of 180 days commencing on the earlier of (A) the expiration of such 30-day period and (B) the delivery of a written notice by the Non-Transferring Member to the Transferring Member rejecting the offer set forth in the Sale Notice (if any) (such 180-day period, the “Sale Period”), be entitled to sell the Subject Membership Interests to any one Third Party at the same or higher price and upon other terms and conditions (excluding price) that are not more favorable to the acquiror than those specified in the Sale Notice, subject to the other terms of this Section 6.3. Any sale process to Transfer the Subject Membership Interests to one or more Third Parties shall, to the maximum extent permitted by applicable Laws and the applicable rules of any stock exchange, not be publicly announced prior to the execution of a definitive agreement and shall be run in accordance with customary practices to ensure a confidential sale process, including requiring potential Third Party acquirors to enter into nondisclosure agreements protecting the Company Group’s and the AEP Outside Group’s confidential information to the maximum extent. If such sale to any Third Party is not completed prior to the expiration of the Sale Period, then the process initiated by the delivery of the Sale Notice shall be lapsed, and the Transferring Member will be required to repeat the process set forth in this Section 6.3 before entering into any agreement with respect to, or consummating, any sale of Membership Interests to any Third Party; provided that if a definitive agreement providing for the consummation of such sale is executed within the Sale Period but such sale has not been consummated at the expiration of the Sale Period solely as a result of a failure to receive the requisite authorization, approval or consent of any Governmental Body in respect of such sale, then the Sale Period shall be extended solely to the extent necessary to permit the receipt of all such authorizations, approvals or consents which are in process but have not been received from the relevant Governmental Body as of the original expiration date of the Sale Period and the consummation of the sale provided for in such definitive agreement; provided, further, that the Transferring Member shall have used its reasonable best efforts in seeking such authorizations, approvals and consents.
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(b)    The Investor Member and its Permitted Transferees (if any) shall not be permitted to Transfer any of their Membership Interests to a Prohibited Competitor without the prior written consent of the AEP Member. Within 10 Business Days after January 1, 2026 (and each year thereafter during the 10-Business Day period beginning on January 1 of the applicable year), the AEP Member shall have the right to update the list of Prohibited Competitors set forth on Schedule 2 (i) to replace no more than three of the Prohibited Competitors with other Competitors designated by the AEP Member in good faith, and (ii) in addition to any replacements pursuant to clause (i), to, in good faith, add up to two additional Prohibited Competitors designated by the AEP Member to such list. Notwithstanding anything to the contrary set forth in this Agreement, this Section 6.3(b) and Schedule 2 (together with the definition of “Prohibited Competitor”) shall automatically terminate and have no further force and effect in the event that the AEP Member and its Permitted Transferees, individually or collectively, no longer control the Company.
(c)    No Transfer of Membership Interests by the Investor Member to any Third Party pursuant to Section 6.3(a)(ii) may be effected if it would, or would reasonably be expected to in the reasonable and good faith determination of the AEP Member in consultation with the Board, (i) have a material and adverse effect on the Company Group, or (ii) create a material risk of an adverse Tax or regulatory consequence that would be material to any member of the Company Group or the AEP Outside Group, in any such case in the foregoing clauses (i) and (ii), as a result of the identity of the Third Party transferee, any action taken or reasonably expected to be taken by any Governmental Body with respect to such Transfer, any change in Tax status of the Company caused or reasonably expected to be caused by such Transfer, any terms or conditions of such Transfer, any requirement that the Membership Interests be registered under any applicable securities Laws in connection with or as a result of such Transfer, or any other similar matter. For purposes of this Section 6.3, Section 6.4, Section 6.5(i) and Section 6.6, “control” means (x) the ownership of at least a majority of the issued and outstanding Membership Interests of the Company, or (y) the ability to elect, directly or indirectly, a majority of the Managers of the Company in accordance with this Agreement.
(d)    Prior to the consummation of any Transfer pursuant to Section 6.3(a)(ii), (i) the Transferring Member shall have delivered to the Board and to the Non-Transferring Member evidence reasonably satisfactory to the Board (with the Managers appointed by the Transferring Member abstaining from any such determination) and to the Non-Transferring Member that (A) the transferee is Financially Capable and (B) the Transfer complies with the provisions of Section 6.3(b) (if applicable) and Section 6.3(c) and (ii) if the Transferring Member is Investor Member or a direct or indirect owner of Investor Member and such Transfer would reduce the “Respective Portion” under an ECL, the Transferring Member or the Transferee shall deliver to the Company replacement Credit Support covering such Transferring Member’s applicable portion of ECL Annual Commitment Amount that corresponds to the direct or indirect equity interest in the Company being Transferred.
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Section 6.4    Tag-Along Rights.
(a)    Other than with respect to a Transfer proposed and made in accordance with Section 6.5, in the event that the AEP Member proposes to effect a Transfer (or series of related Transfers) to a Third Party transferee (the “Tag-Along Buyer”) of a number of its Membership Interests (i) constituting more than 25% of the total Membership Interests then outstanding or (ii) that would result in the AEP Member (or any parent entity of AEP Member a transfer of equity of which would be a Transfer for purposes of this Section 6.4) ceasing to control, or to own a majority of the Membership Interests in, the Company (in either case of (i) and (ii), a “Tag-Along Sale”), then the AEP Member shall give the Investor Member written notice (a “Tag-Along Notice”) of such proposed Transfer at least 30 days prior to the consummation of such Tag-Along Sale, setting forth (w) the number of Membership Interests (“Tag-Along Offered Membership Interests”) proposed to be Transferred to the Tag-Along Buyer and the purchase price, (x) the identity of the Tag-Along Buyer, (y) any other material terms and conditions of the proposed Transfer, and (z) the intended dates on which the AEP Member will enter into a definitive agreement in respect of such proposed Transfer and consummate such proposed Transfer.
(b)    Upon delivery of a Tag-Along Notice, the Investor Member shall have the right, (i) in the case of a Tag-Along Sale described under Section 6.4(a)(i), to sell up to its Tag Portion, and (ii) in the case of a Tag-Along Sale described under Section 6.4(a)(ii), to sell up to all of the Membership Interests of the Company held by the Investor Member, in either case at the same price per Membership Interest, for the same form of consideration and pursuant to the same terms and conditions (including time of payment) as set forth in the Tag-Along Notice (or, if different, as such terms and conditions are applicable at the time of the entry into a definitive agreement in respect of, or at the time of the consummation of, the Tag-Along Sale). If the Investor Member wishes to participate in the Tag-Along Sale, then the Investor Member shall provide written notice (the “Tag-Along Election Notice”) to the AEP Member no less than 30 days after the date of the Tag-Along Notice, indicating such election. Such Tag-Along Election Notice shall set forth the number of its Membership Interests that the Investor Member elects to include in the Tag-Along Sale (which number shall not exceed its Tag Portion solely in the case of a Tag-Along Sale described under Section 6.4(a)(i)), and such Tag-Along Election Notice shall constitute such Investor Member’s binding agreement to sell such Membership Interests on the terms and subject to the conditions applicable to the Tag-Along Sale.
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(c) Any Transfer of the Investor Member’s Membership Interests in a Tag-Along Sale shall be on the same terms and conditions as the Transfer of the AEP Member’s Membership Interests in such Tag-Along Sale, except as otherwise provided in this Section 6.4(c). The Investor Member shall be required to make customary representations and warranties in connection with the Transfer of the Investor Member’s Membership Interests, including as to its ownership and authority to Transfer, free and clear of all Liens, the Investor Member’s Membership Interests and shall indemnify and hold harmless, to the fullest extent permitted by applicable Law, the Tag-Along Buyer against all losses of whatever nature arising out of, in connection with or related to any breach of any representation or warranty made by, or agreements, understandings or covenants of the Investor Member, as the case may be, under the terms of the agreements relating to such Transfer of Investor Member’s Membership Interests, in each case not to exceed the equivalent obligations to indemnify and hold harmless the Tag-Along Buyer provided by the AEP Member; provided, that (i) liability for misrepresentation or indemnity shall (as between the AEP Member and the Investor Member) be expressly stated to be several but not joint and the AEP Member and the Investor Member shall not be liable for any breach of covenants or representations or warranties as to the Membership Interests of any other Member and shall not, in any event, be liable for more than its pro rata share (based on the proceeds to be received) of any liability for misrepresentation or indemnity, (ii) the Investor Member shall benefit from any releases of sellers or other provisions in the transaction documentation of general applicability to sellers to the same extent as the AEP Member, (iii) the Investor Member shall not be required in connection with such Tag-Along Sale to agree to any material non-customary covenants (including restrictive covenants such as non-compete and similar provisions that would restrict its or its Affiliates’ business activities), and (iv) the Investor Member shall not be obligated to provide indemnification obligations that exceed its proceeds from the Tag-Along Sale.
(d)    Notwithstanding the foregoing, and for the avoidance of doubt, the Investor Member shall not be entitled to Transfer its Membership Interests pursuant to this Section 6.4 in the event that, notwithstanding delivery of a written notice of election to participate in such Tag-Along Sale pursuant to this Section 6.4, the Investor Member fails to consummate the Transfer of its Membership Interests (on the terms and conditions required by this Section 6.4) in the applicable Tag-Along Sale.
(e)    For the avoidance of doubt, (i) the terms of this Section 6.4 apply to any Transfers of any Membership Interests by a Permitted Transferee of the AEP Member that would otherwise constitute a Tag-Along Sale, and (ii) the rights conferred to the Investor Member under this Section 6.4 do not apply in the event of a Change in Control of AEP Parent.
Section 6.5    Drag-Along Rights.
(a)    Following the expiration of the Lock-up Period and subject in all respects to Section 6.1(b), in the event that the AEP Member intends to effect a sale of all of the Membership Interests owned by the AEP Member and such Membership Interests constitute at least a majority of the issued and outstanding Membership Interests of the Company (a “Drag-Along Sale”), then the AEP Member shall have the option (but not the obligation) to require the Investor Member to Transfer all (and not less than all) of its Membership Interests to the Third Party buyer (the “Drag-Along Buyer”) (or to such other Person as the Drag-Along Buyer directs) in accordance with the provisions of this Section 6.5 (such right of the AEP Member, the “Drag-Along Right”).
(b) If the AEP Member elects to exercise the Drag-Along Right pursuant to Section 6.5(a), then the AEP Member shall send a written notice to the Investor Member (a “Drag-Along Notice”) specifying (i) that the Investor Member is required to Transfer all of its Membership Interests pursuant to this Section 6.5, (ii) the amount of cash consideration payable for the Investor Member’s Membership Interests, (iii) the name of the Third Party to which the Investor Member’s Membership Interests are to be Transferred (or which is otherwise entitled to direct the disposition thereof at the consummation of the Drag-Along Sale), (iv) any other material terms and conditions of the proposed Transfer, and (v) the intended dates on which the AEP Member will enter into a definitive agreement in respect of such proposed Transfer and consummate such proposed Transfer.
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(c)    In the event that the AEP Member elects to exercise the Drag-Along Right, then the Investor Member hereby agrees with respect to all Membership Interests it holds:
(i)    in the event such transaction requires the approval of Members, to vote (in person, by proxy or by action by written consent, as applicable) all of its Membership Interests in favor of such Drag-Along Sale;
(ii)    to execute and deliver all related documentation and take such other action reasonably necessary to enter into definitive agreements in respect of and to consummate the proposed Drag-Along Sale in accordance with, and subject to the terms of, this Section 6.5; and
(iii)    not to deposit its Membership Interests in a voting trust or subject any Membership Interests to any arrangement or agreement with respect to the voting of such Membership Interests, unless specifically requested to do so by the Drag-Along Buyer in connection with a Drag-Along Sale.
(d)    Subject to Section 6.5(e), any Transfer of the Investor Member’s Membership Interests in a Drag-Along Sale shall be on the same terms and conditions as the proposed Transfer of the AEP Member’s Membership Interests in the Drag-Along Sale. Upon the request of the AEP Member, the Investor Member shall be required to make customary representations and warranties in connection with the Transfer of the Investor Member’s Membership Interests, including as to its ownership and authority to Transfer, free and clear of all Liens, its Membership Interests, and shall indemnify and hold harmless, to the fullest extent permitted by applicable Law, the Drag-Along Buyer against all losses of whatever nature arising out of, in connection with or related to any breach of any representation or warranty made by, or agreements, understandings or covenants of the Investor Member as the case may be, under the terms of the agreements relating to such Transfer of the Investor Member’s Membership Interests, in each case not to exceed the equivalent obligations to indemnify and hold harmless the Tag-Along Buyer provided by the AEP Member; provided, that (i) liability for misrepresentation or indemnity shall (as between the AEP Member and the Investor Member) be expressly stated to be several but not joint and the AEP Member and the Investor Member shall not be liable for any breach of covenants or representations or warranties as to the Membership Interests of any other Member and shall not, in any event, be liable for more than its pro rata share (based on the proceeds to be received) of any liability for misrepresentation or indemnity, (ii) the Investor Member shall benefit from any releases of sellers or other provisions in the transaction documentation of general applicability to sellers to the same extent as the AEP Member and (iii) the Investor Member shall not be obligated to provide indemnification obligations that exceed its proceeds from the Drag-Along Sale.
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(e)    Any Transfer required to be made by the Investor Member pursuant to this Section 6.5 shall be for consideration consisting solely of cash. Without the consent of the Investor Member, the Investor Member shall not be required in connection with such Drag-Along Sale to agree to any material non-customary covenants (including restrictive covenants such as non-compete and similar provisions that would restrict its or its Affiliates’ business activities).
(f)    At the consummation of the Drag-Along Sale, the Investor Member shall Transfer all of its Membership Interests to the Drag-Along Buyer (or its designee), and the Drag-Along Buyer shall pay the consideration due for the Investor Member’s Membership Interest. If the Investor Member has failed, as of immediately prior to the time that the consummation of the Drag-Along Sale would otherwise have occurred, to have taken all actions necessary in accordance with this Agreement to consummate the Transfer of the Membership Interests held by it, then the Investor Member shall be deemed to be in material breach of this Agreement for purposes of Article IV and for all other purposes hereunder, and shall be deemed to have granted (and hereby grants, contingent only on the occurrence of such failure) an irrevocable appointment of any Person nominated for the purpose by the AEP Member to be the Investor Member’s agent and attorney to execute all necessary documentation and instruments on its behalf to Transfer the Investor Member’s Membership Interest to the Drag-Along Buyer (or as it may direct) as the holder thereof, in each case consistent with the terms set forth in this Section 6.5.
(g)    The AEP Member shall have a period of 180 days commencing on the delivery of the Drag-Along Notice (such 180-day period, the “Drag Sale Period”) to consummate the Drag-Along Sale. If the Drag-Along Sale is not completed prior to the expiration of the Drag Sale Period, then the process initiated by the delivery of the Drag-Along Notice shall be lapsed, and the AEP Member will be required to repeat the process set forth in this Section 6.5 to pursue any Drag-Along Sale; provided that if a definitive agreement providing for the consummation of such Drag-Along Sale is executed within the Drag Sale Period but such Drag-Along Sale has not been consummated at the expiration of the Drag Sale Period solely as a result of a failure to receive the requisite authorization, approval or consent of any Governmental Body in respect of such Drag-Along Sale, then the Drag Sale Period shall be extended solely to the extent necessary to permit the receipt of all such authorizations, approvals or consents which are in process but have not been received from the relevant Governmental Body as of the original expiration date of the Drag Sale Period and the consummation of the Drag-Along Sale provided for in such definitive agreement; provided, further, that the AEP Member shall have used efforts in seeking such authorizations, approvals and consents consistent with its obligations under such definitive agreement(s) in respect thereof.
(h) Notwithstanding the foregoing, the AEP Member may not exercise the Drag-Along Right or consummate any Drag-Along Sale without the prior written consent of the Investor Member unless the applicable Drag-Along Sale would result in the Investor Member receiving cash proceeds resulting in it achieving at least an IRR of 10% (the “Investor Return Threshold”) and a MOIC of 2.15x (the “MOIC Return Threshold”); provided, that any shortfall in the Investor Member achieving the higher of the Investor Return Threshold or the MOIC Return Threshold may be paid by the AEP Member to the Investor Member in immediately available funds at the closing of the Drag-Along Sale, in which case the prior written consent of the Investor Member shall not be required to exercise the Drag-Along Right or consummate such Drag-Along Sale.
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(i)    For the avoidance of doubt, the rights conferred to the AEP Member under this Section 6.5 do not apply in the event of, or following, a Change in Control of AEP Transmission or at any time AEP Parent does not directly or indirectly control the Company.
Section 6.6    Put Option.
(a)    The AEP Member and the Company shall provide Investor Members written notice (an “Option Notice”) of AEP Parent or any of its Affiliates entering into any Contract relating to a transaction (excluding any Tag-Along Sale for which the Investor Members have received a Tag-Along Notice) that would result in the Company no longer being majority owned and controlled directly or indirectly by AEP Parent (such transaction, a “Put Transaction”), which such Option Notice shall be delivered to the Investor Members no later than the earlier of (i) five (5) Business Days following entrance into any such Contract related to a Put Transaction or (ii) at least twenty (20) Business Days prior to consummation of such Put Transaction and shall include the AEP Member’s good faith determination of the Fair Market Value of the Membership Interests of each Investor Member together with reasonable supporting documentation thereof. The Investor Members shall have the option (exercisable collectively by a majority-in-interest (based on Percentage Ownership) of the Investor Members, and not individually), in their sole discretion, to elect to require that all (but not less than all) of the Membership Interests of all of the Investor Members be purchased by the AEP Member (or its designee) for cash in connection with such Put Transaction. If the Investor Members collectively so elect to exercise such option, such electing Investor Members (constituting at least a majority-in-interest (based on Percentage Ownership) of the Investor Members) shall deliver written notice of such election (the “Put Notice”) to the Company and AEP Member no later than twenty (20) Business Days following receipt of the Option Notice, and which Put Notice specifies whether the electing Investor Members agree with the Fair Market Value determination of their Membership Interests provided by the AEP Member or dispute such determination pursuant to Section 13.15. If the Investor Members fail to timely deliver a Put Notice in accordance with the immediately prior sentence, the Investor Members shall be deemed to have waived their option described in this Section 6.6 with respect to the applicable Put Transaction. For purposes of any dispute with respect to the Fair Market Value of the Membership Interests of the Investor Members: (x) initiating a dispute with respect to the Fair Market Value determination of the Membership Interests in connection with a Put Transaction shall require consent by a majority-in-interest (based on Percentage Ownership) of the Investor Members, (y) a majority-in-interest (based on Percentage Ownership) of the Investor Members shall make all decisions on behalf of all Investor Members in respect of the applicable Fair Market Value determination pursuant to Section 13.15, and (z) any determination of the Fair Market Value of the Membership Interests in connection with a Put Sale (as defined below) pursuant to Section 13.15 shall be binding on all Investor Members.
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(b)    Upon receipt of the Put Notice, the AEP Member (or its designee) shall purchase all of the Membership Interests of all of the Investor Members no later than the later of (i) five (5) Business Days following receipt of the applicable Put Notice or (ii) the closing date of the Put Transaction (it being understood that such purchase is contingent upon, and is not occurring prior to, the closing of the applicable Put Transaction) (in each case, as may be extended (x) in order to finally determine Fair Market Value pursuant to Section 13.15 solely for the portion of consideration in dispute and (y) to obtain any requisite authorization, approval or consent of any Governmental Body) (the “Put Sale”). The consideration to be paid by the AEP Member (or its designee) to each Investor Member in respect of the applicable Membership Interests shall be the Fair Market Value thereof (without giving effect to any transaction costs of the Company Group associated with the Put Transaction, it being understood such shall not be borne directly or indirectly by the Investor Members participating in the Put Sale) as of the date of the Put Sale, less (without duplication) any then-outstanding balance (including principal and accrued interest) of all Unfunded Amount Loans owed by such Investor Member. The AEP Member (or its designee) shall pay the purchase price payable in the Put Sale in cash by wire transfer of immediately available funds to an account designated in writing by the applicable Investor Member. Notwithstanding the foregoing, if the Investor Members initiate a dispute pursuant to Section 13.15 with respect to the AEP Member’s determination of Fair Market Value, then the Investor Members constituting at least a majority-in-interest (based on Percentage Ownership) of the Investor Members may, by written notice to the AEP Member and the Company, revoke any Put Notice within five (5) Business Days of final determination of Fair Market Value pursuant to Section 13.15 and thereafter the Investor Members shall have no obligation to sell their Membership Interests pursuant to the applicable Put Sale. If the Investor Members fail to timely revoke their Put Notice within such timeframe in accordance with the immediately prior sentence, the Investor Members shall continue to be bound to sell their Membership Interests pursuant to this Section 6.6.
Section 6.7 Cooperation. The Members and the Company acknowledge and agree that each of them shall cooperate (and the AEP Member and the Company shall cause their respective Affiliates to cooperate) reasonably to obtain the requisite authorization, approval or consent of any Governmental Body or material third party necessary to consummate any Transfers contemplated or permitted by this Article VI. The Members shall have the right in connection with any Transfer of Membership Interests permitted by this Agreement (or in connection with the investigation or consideration of any such potential Transfer) to require the Company to reasonably cooperate with (and the AEP Member and the Company shall cause their respective Affiliates to reasonably cooperate with) potential purchasers in such prospective Transfer (at the sole cost and expense of the applicable Member or such potential purchasers) by taking such actions reasonably requested by the applicable Member or such potential purchasers, including (a) preparing or assisting in the preparation of due diligence materials, (b) providing access to the Company’s and each of its Subsidiaries’ books, records, properties and other materials (subject, in each case, to the execution of customary confidentiality and non-disclosure agreements) to potential purchasers, and (c) making the directors, managers, officers, employees (if any) and other Representatives of the Company Group and any centralized service company Affiliate of the Company that provides services to the Company Group available to potential purchasers for a reasonable number of presentations and due diligence interviews; provided that no such cooperation by the Company shall be required (i) until the relevant potential purchaser executes and delivers to the Company a customary confidentiality agreement, (ii) to the extent such cooperation would unreasonably interfere with the normal business operations of the Company or any of its Subsidiaries, and (iii) to the extent the provision of any information would (A) conflict with, or constitute a violation of, any applicable Law or Order or cause a loss of attorney-client privilege of the Company or any of its Subsidiaries, (B) in the AEP Member’s reasonable, good faith determination, require the disclosure of any information that is proprietary, confidential or sensitive to the AEP Member or to any other member of the AEP Outside Group (but solely to the extent of withholding such information), or (C) require the disclosure of any information relating to any joint, combined, consolidated or unitary Tax Return that includes the AEP Member or any other member of the AEP Outside Group or any supporting work papers or other documentation related thereto (other than any portion thereof relating solely to the Company or any of its Subsidiaries or relating to the Tax Allocation Agreement (and any amendment thereof)).
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ARTICLE VII
PREEMPTIVE RIGHTS
Section 7.1 Preemptive Rights. The Company hereby grants to each Member the right to purchase such Member’s Preemptive Right Share of all (or any part) of any New Securities that the Company may from time to time issue after the date of this Agreement (the “Preemptive Right”); provided, that no Non-Contributing Member shall have a Preemptive Right with respect to New Securities issued pursuant to Section 5.1 as a result of such Non-Contributing Member’s failure to make all or any portion of its Pro Rata Request Amount. In the event the Company proposes to undertake an issuance of New Securities (in a single transaction or a series of related transactions), the Company shall give to each Member written notice of its intention to issue New Securities (the “Preemptive Right Participation Notice”), describing the amount and type of New Securities, the cash purchase price and the general terms upon which it proposes to issue such New Securities. Each Member shall have 10 Business Days from the date of receipt of any such Preemptive Right Participation Notice (the “Preemptive Right Notice Period”) to agree in writing to purchase for cash up to such Member’s Preemptive Right Share of such New Securities for the price and upon the terms and conditions specified in the Preemptive Right Participation Notice by giving written notice to the Company and stating therein the quantity of New Securities to be purchased (not to exceed such Member’s Preemptive Right Share) as well as the maximum number of New Securities it would purchase. If any Member fails to so respond in writing within the Preemptive Right Notice Period, then such Member shall forfeit the right hereunder to purchase its Preemptive Right Share of such New Securities and the Company will allocate the rights to purchase such New Securities to any other Member that indicated it would purchase New Securities in excess of its Preemptive Right Share based on their relative Preemptive Right Shares. Subject to obtaining the requisite authorization, approval or consent of any Governmental Body, the closing of any purchase by any Member pursuant to this Section 7.1 shall be consummated concurrently with the consummation of the issuance or sale described in the Preemptive Right Participation Notice. The Company shall be free to complete the proposed issuance or sale of New Securities described in the Preemptive Right Participation Notice with respect to any New Securities not elected to be purchased pursuant to this Section 7.1 in accordance with the terms and conditions set forth in the Preemptive Right Participation Notice (except that the amount of New Securities to be issued or sold by the Company may be reduced).
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Notwithstanding anything to the contrary, a Member may delegate their Preemptive Rights to a Person that would qualify as a Permitted Transferee and the rights afforded to such Member pursuant to this Section 7.1 shall apply to such Person that would qualify as a Permitted Transferee mutatis mutandis.
ARTICLE VIII
PROTECTIVE PROVISIONS
Section 8.1    Investor Member No Threshold Matters. Notwithstanding anything to the contrary in this Agreement, the Company and its Subsidiaries shall not cause or permit, in each case, without the prior written consent of the Investor Member (except that no such written consent shall be required to the extent that such matter is necessary to comply with applicable Law or Order):
(a)    the issuance of any equity interests by any of the Company’s Subsidiaries to any Person that is not the Company or one of its Subsidiaries;
(b)    the taking of any action that would reasonably be expected to result in the Company not being classified as a corporation for U.S. federal income Tax purposes (or applicable state and local Taxes purposes), the making, revoking or changing of any Tax classification of the Company’s Subsidiaries, or taking any other material action related to Taxes that would result in disproportionate and adverse consequence to the Investor Member;
(c)    except pursuant to and in accordance with Section 5.1, (i) any non-pro rata distribution, repurchase or redemption of any equity interests issued by the Company or (ii) effecting any Membership Interest split, distribution or other recapitalization transaction that would alter Investor Member’s respective Percentage Interest as of immediately prior to such transaction;
(d)    the transfer, sale or other disposition, whether by way of asset sale, stock sale, merger or otherwise, of all or substantially all of the assets of the Company and the Company’s Subsidiaries, taken as a whole on a consolidated basis (it being understood, for the avoidance of doubt, that this Section 8.1(d) shall not be deemed to restrict a transfer, sale or other disposition of the equity of the Company);
(e)    any amendment or modification to any Organizational Document of the Company or any Subsidiary of the Company, other than (i) ministerial amendments thereto or (ii) amendments thereto that would not have an adverse impact on the Investor Member;
(f)    any election that would cause the Company to be treated as a “real estate investment trust” (within the meaning of Section 856 of the Code);
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(g) the entry into, amendment or termination of, or waiver of any material right under, any Affiliate Transaction (which shall not be deemed to include any corporate allocations involving the Company or any of its Subsidiaries that are made in compliance with Section 2.14; provided that, all corporate and cost allocations that relate to clause (i) of the definition of Company Business (e.g., non-corporate support services) that are not reasonably expected to be included or recoverable in the FERC-regulated rate base or that are not reasonably expected to be approved in the FERC rate-making process shall be subject to this Section 8.1(g)), other than Affiliate Transactions that satisfy each of the following requirements: (i) any and all such Affiliate Transactions are entered into on terms that are no less favorable in the aggregate to the Company (or the relevant Subsidiary thereof party thereto) than reasonably would be obtainable from an unaffiliated third party (it being agreed that any pricing or other terms that are compulsory under applicable Law shall be deemed to constitute an arm’s length term for purposes of this clause (i)); (ii) with respect to any Affiliate Transactions involving revenues or expenditures that are not reasonably expected to be, included or recoverable in the FERC-regulated rate base or that are not reasonably expected to be approved in the FERC rate-making process (“Non-Qualifying Transactions”), such revenues or expenditures are less than $5,000,000 per Contract, transaction or series of related transactions individually and less than $15,000,000 in the aggregate for any fiscal year for all such Non-Qualifying Transactions; and (iii) without limiting the foregoing clause (ii), any and all such Affiliate Transactions (inclusive of Non-Qualifying Transactions) involve revenues or expenditures of less than $15,000,000 per Contract, transaction or series of related transactions individually and less than $40,000,000 in the aggregate for any fiscal year for all such Affiliate Transactions (it being acknowledged and agreed that no prior written consent of the Investor Member will be required with respect to any amendments to any Affiliate Transaction made in the ordinary course of business unless and only to the extent such amendment would adversely affect the Company or its relevant Subsidiary party thereto in any material respect);
(h)    any amendment of the Project Selection Guidelines that would reasonably be expected to reduce in any material respect the Target CapEx allocated to the Company Group;
(i)    any amendment or modification of the American Electric Power Company, Inc. and its Consolidated Affiliates – 2024 Tax Agreement Regarding Method of Allocating Consolidated Income Taxes in effect as of the date hereof, among AEP Parent, the Company and the other parties thereto (or any replacement agreement thereof entered into among AEP Parent, the Company and certain other Subsidiaries of the AEP Parent for the purpose of allocating and indemnifying for consolidated tax liabilities) (the “Tax Allocation Agreement”), that would reasonably be expected to have a material impact on the amount for which the Company would be responsible for or entitled to under the Tax Allocation Agreement or would adversely impact the indemnification rights of the Company thereunder in any material respect; or
(j)    the entry into any binding agreement or arrangement by the Company or any of its Subsidiaries to effect any of the foregoing actions.
Section 8.2 Investor Member Threshold Matters. Notwithstanding anything to the contrary in this Agreement, the Company and its Subsidiaries shall not cause or permit, in each case, without the prior written consent of the Investor Member, for so long as the Investor Member (together with its Affiliates) holds a Percentage Interest equal to or greater than 9.9% (unless such matter is necessary (i) to comply with applicable Law or Order, or (ii) with respect to clauses (d), (e) or (h) or, to the extent related to the foregoing, (q), in response to an Emergency Situation):
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(a)    any material change to any line or scope of the existing business of the Company or any of its Subsidiaries;
(b)    the conversion of the Company or any of its Subsidiaries from its current legal business entity form to any other business entity form (e.g., the conversion of the Company from a Delaware limited liability company to a Delaware corporation);
(c)    without limiting the requirements of Section 2.14, the direct or indirect acquisition by the Company or any of the Company’s Subsidiaries (whether by merger or consolidation, acquisition of assets or stock or by formation of a joint venture or otherwise), or any request for capital in connection therewith, (i) of any equity interests of any member of the AEP Outside Group, or (ii) of any business, assets or operations of any member of the AEP Outside Group, in either case having a Fair Market Value in excess of 1.5% of the Rate Base Amount in the aggregate in any calendar year, other than Qualifying Core Assets;
(d)    the transfer, sale or other disposition, whether by way of asset sale, stock sale, merger or otherwise, of any business, assets or operations of the Company or any of the Company’s Subsidiaries having a Fair Market Value in excess of 2.5% of the Rate Base Amount in one or more transactions in any calendar year, other than Qualifying Core Assets;
(e)    other than in connection with capital expenditures (which are addressed in subparagraph (g) below), any acquisition of assets, including equity securities, or any request for capital in connection therewith, by the Company or any of its Subsidiaries from a Third Party the aggregate purchase price of which exceeds 1.5% of the Rate Base Amount in any calendar year, other than Qualifying Core Assets;
(f)    (i) any acquisition of assets, including equity securities, or any request for capital in connection therewith, by the Company or any of its Subsidiaries from a Third Party if the aggregate purchase price of all such transactions (on an enterprise value basis for any business or operations) exceeds $1,000,000,000 in any calendar year or (ii) any transfer, sale or other disposition, whether by way of asset sale, stock sale, merger or otherwise, of any business, assets or operations of the Company or any of the Company’s Subsidiaries if the Fair Market Value of such business, assets or operations (on an enterprise value basis for any business or operations) exceeds $1,000,000,000 in any calendar year;
(g)    any capital expenditure by the Company or its Subsidiaries, or any request for capital in connection therewith, that exceeds in the aggregate 1.0% of the Rate Base Amount in any calendar year and that is not (i) made in connection with obtaining, constructing or otherwise acquiring a Qualifying Core Asset, or (ii) reasonably necessary to fund any Emergency Expenditures;
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(h)    the incurrence of Indebtedness (other than the refinancing of existing Indebtedness on commercially reasonable terms reflecting then-current credit market conditions) by the Company or any of its Subsidiaries that would reasonably be expected to result in the Company’s Debt-to-Capital Ratio equaling or exceeding (after giving pro forma effect to such incurrence and the application of the proceeds therefrom) the then-current target Debt-to-Capital Ratio approved by FERC by more than 400 basis points for four consecutive fiscal quarters; provided, that the Company, to the extent reasonably practicable, shall notify the Investor Member at least 10 Business Days prior to the Company or any of its Subsidiaries incurring any Indebtedness in excess of $25,000,000 more than the amount set forth in the annual budget;
(i)    except pursuant to and in accordance with Section 4.3, the liquidation, dissolution, winding up of the Company or any of its Subsidiaries (other than Subsidiaries that no longer conduct any material business) or the filing of a petition seeking relief, or the consent to the entry of a decree or order for relief in an involuntary case, under the bankruptcy, rearrangement, reorganization, or other debtor relief Laws of the United States or any state or any other competent jurisdiction or a general assignment for the benefit of its creditors by the Company or any of its Subsidiaries;
(j)    the listing of any equity interests of the Company (or a successor to the Company, including by merger, conversion or other reorganization) on any stock exchange;
(k)    the entrance into any Contract, commitment or understanding that by its terms would materially restrict or alter the Company’s right to make distributions to the Members in accordance with this Agreement or the Investor Member’s right to transfer its Membership Interest in accordance with this Agreement (including any Contract whereby the Investor Member’s transfer of all or a portion of its Membership Interest in accordance with this Agreement would result in a breach or default having a material adverse effect on the Company Group);
(l)    the entrance into any joint venture, partnership or similar agreement, unless the aggregate amount of cash, property or other assets anticipated to be contributed by the Company or its applicable Subsidiary to such joint venture or partnership is less than 1.5% of the Rate Base Amount, or such joint venture, partnership or similar interests (or the cash, property or other assets so contributed to such joint venture or partnership) would continue to qualify as Qualifying Core Assets;
(m)    material decisions relating to the conduct (including the settlement) of any litigation or other legal administrative, or criminal proceeding to which the Company or any of its Subsidiaries is a party where (i) it is reasonably expected that the liability of the Company and its Subsidiaries would exceed $50,000,000 in the aggregate or (ii) such proceeding would reasonably be expected to have an adverse effect on the Investor Member or any of its Affiliates in any material respect (other than in its or (if applicable, their) capacity as an investor in the Company); provided, that, for the avoidance of doubt, the foregoing shall not be applicable to any ordinary course regulatory proceedings (including rate cases and other rate proceedings) that do not involve claims of criminal conduct or intentional violations of applicable Law;
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(n)    making any change to the Total Number of Managers that would result in Investor Member having the ability to appoint fewer Investor Managers than contemplated pursuant to the first sentence of Section 2.2(b);
(o)    making any political or charitable contribution made by the Company or any of its Subsidiaries to any Governmental Body or any official, representative or staff thereof, including any community leaders or elected officials or candidates for public office; or
(p)    the entry into any binding agreement or arrangement by the Company or any of its Subsidiaries to effect any of the foregoing actions.
Section 8.3    Consultation Matters. For so long as (x) an Investor Member’s Percentage Interest (together with its Affiliates) is equal to or greater than 9.9% and (y) such Investor Member is not a Defaulting Member, the Company (and, as applicable, the Board) shall use its reasonable best efforts to consult in good faith with such Investor Member (which consultation shall be deemed to include the participation of Investor Managers in the meetings of the Board with respect to such matters, and, to the extent requested by such Investor Member, reasonable discussions between Representatives of the Company, of the Investor Member and of the AEP Member) prior to the Company undertaking, or causing or permitting any of its Subsidiaries to undertake, any of the following matters (except as would be impracticable in respect of a particular action that the Board reasonably believes to be necessary or appropriate to comply with applicable Law, Order or in response to an Emergency Situation):
(a)    Establishing, materially amending and materially deviating from the annual budget and business plan of the Company and its Subsidiaries;
(b)    without limiting the Investor Member’s rights under Section 8.2(m), settling or compromising any arbitration, lawsuit, proceeding or regulatory process (i) with a settlement or compromise amount in excess of 2.5% of the Rate Base Amount, or (ii) that has material non-monetary penalties or obligations on the Company and/or any of its Subsidiaries; and
(c)    the appointment or replacement of the President (or any successor position thereof, however titled or restyled) of the Company or any of its Subsidiaries.
Section 8.4    Actions by the Investor Manager on behalf of the Investor Member. Where any action requires the consent of the Investor Member pursuant to Section 8.2, if there are Investor Managers then serving and the Investor Managers collectively shall, unless the Investor Member indicates in writing to the AEP Member otherwise, have the authority to provide such consent on behalf of the Investor Member who appointed such Investor Manager(s) (but only if the Investor Managers are acting unanimously) at any meeting of the Board called to discuss such matters, and the Company, the other Members and the other Managers shall be entitled to rely on such action of the applicable Investor Manager as an action of such Investor Member with such action being binding upon such Investor Member.
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Section 8.5    Acknowledgement of Purpose of Provisions. It is hereby acknowledged and agreed by the Parties that the rights of the Investor Member set forth in this Article VIII are protection mechanisms for the Investor Member acting in its capacity as an investor in the Company and are not for purposes of, and should not be construed or otherwise interpreted as, providing the Investor Member or any of its Representatives or Affiliates with the ability to take any action that would constitute exercising substantial influence or control over the Company or any of its Subsidiaries or would otherwise provide the Investor Member or any of its Representatives or Affiliates with any right to direct the operation of the business of the Company or any of its Subsidiaries. Nothing contained in this Agreement (including this Article VIII) shall be deemed to give the Investor Member the right to prohibit or restrict any repayment of the AEP TransCo Note in accordance with its terms that is approved by the Board.
ARTICLE IX
OTHER COVENANTS AND AGREEMENTS
Section 9.1    Books and Records.
(a)    The Company shall keep and maintain, or cause to be kept and maintained, books and records of accounts, taxes, financial information and all matters pertaining to the Company and its Subsidiaries at the principal offices and place of business of the Company in a commercially reasonable manner consistent with the manner in which similar books and records are kept and maintained by other members of the AEP Outside Group. Each Member (other than any Defaulting Member) and its duly authorized Representatives shall have the right to, at reasonable times during normal business hours, upon reasonable notice, under supervision of the Company’s or, in the case of the Investor Member, the AEP Outside Group’s or the Company Group’s, as applicable, personnel and in such a manner as to not unreasonably interfere with the normal operations of any member of the Company Group, (i) visit and inspect the books and records of the Company Group, and, at its expense, make copies of and take extracts from any books and records of the Company Group and (ii) meet and consult with officers, other managers of the Company Group and Representatives of the Company Group regarding their businesses and activities; provided that, in the case of the Investor Member, any Person gaining access to such information regarding the Company Group pursuant to this Section 9.1 shall agree to hold in strict confidence, not make any disclosure of, and not use for purposes other than good faith administration of the Investor Member’s continuing investment, all information regarding any member of the Company Group that is not otherwise publicly available.
(b) Notwithstanding the foregoing, the Company shall not be obligated to provide to the Investor Member any record or information (i) relating to the negotiation and consummation of the transactions contemplated by this Agreement and the Contribution Agreement, including confidential communications with Representatives or Advisors, including legal counsel, representing the Company or any of its Affiliates, (ii) that is subject to an attorney-client or other legal privilege, (iii) that, in the AEP Member’s reasonable determination, are proprietary, confidential or sensitive to the AEP Member or to any other member of the AEP Outside Group (including, for the avoidance of doubt, proprietary information related to system planning, technical operations, engineering, construction, maintenance and procurement matters for transmission systems and transmission projects, including critical energy/electric infrastructure information (CEII), or customer information), (iv) relating to any joint, combined, consolidated or unitary Tax Return that includes the AEP Member or any other member of the AEP Outside Group or any supporting work papers or other documentation related thereto (other than any portion thereof relating solely to the Company or any of its Subsidiaries or relating to the Tax Allocation Agreement (and any amendment thereof)), or (v) the provision of which would violate any applicable Law or be inconsistent with any Order or any other restriction on the use of such information by a Governmental Body.
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(c)    On a quarterly basis, the Company shall provide Investor Member available health, safety and environmental information for the Company Group that is reasonably requested by Investor Member.
(d)    Each Member shall reimburse the Company for all documented out-of-pocket costs and expenses incurred by the Company in connection with such Member’s exercise of its inspection and information rights pursuant to this Section 9.1.
Section 9.2    Financial Reports. The Company shall provide, or otherwise make available, to any Member (unless such Member is a Defaulting Member):
(a)    on an annual basis, (i) within 110 days after the end of each fiscal year, an audited consolidated balance sheet, statement of operations and statement of cash flow the Company and (ii) as soon as reasonably practicable after filing with FERC, each FERC Form No. 1 financial report of each Subsidiary of the Company that is required to file such a financial report;
(b)    on a quarterly basis, (i) within 60 days after the end of each fiscal quarter, an unaudited consolidated balance sheet and related quarterly and year-to-date statement of operation and statement of cash flow of the Company and (ii) as soon as reasonably practicable after filing with FERC, each FERC Form No. 3-Q financial report of each Subsidiary of the Company that is required to file such a financial report;
(c)    on an annual basis, as soon as reasonably practicable after the approval thereof by the Board, the annual budget and business plan (if applicable) for each member of the Company Group;
(d)    on an annual basis, as soon as reasonably practicable after the approval thereof by the Board, financial forecasts for each member of the Company Group for the fiscal year, which shall be in such manner and form as approved by the Board, and which shall include a projection of all anticipated Additional Funding Requirements, a projection of income, a projected cash flow statement, and projections of Available Cash and projected distributions for each fiscal quarter in such fiscal year and a projected balance sheet as of the end of each fiscal quarter in such fiscal year; and
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(e)    on a semi-annual basis, a report of the allocated Target CapEx under the Project Selection Guidelines, including the amount of Target CapEx incurred by each member of the Company Group, on the one hand, and any member of the AEP Outside Group, on the other hand.
Section 9.3    Other Business; Corporate Opportunities.
(a)    To the extent permitted by applicable Law and, in the case of the AEP Member, subject to its compliance with its obligations under Section 9.3(b), any Member and any Affiliate of any Member may engage in, possess an interest in or otherwise be involved in other business ventures of any nature or description, independently or with others, similar or dissimilar to the businesses of the Company Group, and neither the Company nor any Member shall have any rights by virtue of this Agreement in and to such independent ventures or the income or profits derived therefrom, and the pursuit of any such venture, even if competitive with the businesses of the Company Group, shall be deemed not to be wrongful or improper so long as it is consistent with all Laws applicable to the Company Group.
(b)    Each Member acknowledges that the Company Group is subject to, and the AEP Member shall cause all of its Affiliates that pursue Target Projects (including, for the avoidance of doubt, the Existing OpCos) to be subject to, the Project Selection Guidelines. The AEP Member shall (and the AEP Member shall cause its Affiliates to) allocate all Target Projects that the AEP Member or any of its Affiliates (including the Company Group) intend to pursue to the Company Group, except (i) with the prior written consent of the Investor Member or (ii) with respect to Target Projects that are allocated to the Existing OpCos pursuant to Sections 4.2 or 4.3 of the Project Selection Guidelines, as interpreted in good faith, in a manner that is non-discriminatory to the Company Group and no less favorable in any material respect to the Company Group (i.e., it being less favorable for the Company Group to receive less Target CapEx) than the manner in which the AEP Member and its Affiliates have interpreted the Project Selection Guidelines and made allocation decisions in accordance therewith prior to the date hereof; provided, that the AEP Member shall have no obligation to allocate Target Projects to the Company Group if such allocation would, on the advice of counsel, be reasonably expected to violate any Law or be inconsistent with any Order or documented guidance of a Governmental Body having jurisdiction over a relevant member of the AEP Outside Group or the Company Group.
(c) The AEP Member shall (and shall cause its Affiliates to) conduct an internal audit of the application by the AEP Outside Group, and by the Company Group to the extent applicable, of the Project Selection Guidelines with respect to Target Projects no less than every two years and shall share such audit report with Investor Member. Not more than once every four years, the Investor Member shall be entitled (but not obligated) to cause to be conducted by an independent accounting or consulting firm reasonably acceptable to the AEP Member an audit and review of the application of the Project Selection Guidelines with respect to Target Projects for the prior four year period (at Investor Member’s sole cost); provided that Investor Member shall be entitled to cause one such independent audit with respect to the four-year period from January 1, 2030 through December 31, 2034 even if there was a prior independent audit within the four years preceding such audit. If, on a cumulative basis, in any four year period from and after January 1, 2025 through December 31, 2034 (evaluated annually as of the end of the applicable calendar year beginning in calendar year 2028), the Company Group has been allocated Target CapEx comprising less than the applicable Target CapEx Floor Percentage of all Target CapEx during such four-year period, then the Investor Member and the AEP Member shall negotiate in good faith to create and implement a plan of specific actions consistent with Prudent Utility Practices, to the extent reasonably within the control of the AEP Outside Group and the Company Group and not reasonably expected to violate any Law or be inconsistent with any Order or documented guidance of a Governmental Body having jurisdiction over a relevant member of the AEP Outside Group or the Company Group, for the Company Group to be allocated Target CapEx going forward in excess of the applicable Target CapEx Floor Percentage of all Target CapEx.
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(d)    The Company and each Member expressly acknowledge and agree, that, except as set forth in Section 9.3(b), (i) neither the Members nor any of their respective Affiliates or Representatives shall have any duty to communicate or present an investment or business opportunity to the Company Group in which the Company Group may, but for the provisions of this Section 9.3, have an interest or expectancy (a “Corporate Opportunity”), and (ii) neither of the Members nor any of their respective Affiliates or Representatives (even if such Person is also an officer, director or Manager of the Company or any of its Subsidiaries) shall be deemed to have breached any duty or obligation to the Company Group by reason of the fact that such Person pursues, acquires or engages in a Corporate Opportunity for itself or directs, sells, assigns or transfers such Corporate Opportunity to another Person or does not communicate information regarding such Corporate Opportunity to the Company Group. The Company and each Member expressly renounce any interest in Corporate Opportunities and any expectancy that a Corporate Opportunity will be offered to the Company Group.
Section 9.4    Compliance with Laws.
(a)    The Company shall not, and shall cause its Subsidiaries not to, and shall use its commercially reasonable efforts to ensure that the Company Group’s respective Representatives shall not in the course of their actions for, or on behalf of, any Member of the Company Group:
(i)    offer promise, provide or authorize the provision of any money, property, contribution, gift, entertainment or other thing of value, directly or knowingly indirectly, to any government official or other Person (i.e., commercial bribery), to unlawfully influence official action or secure an improper advantage, to unlawfully encourage the recipient to improperly influence or affect any act or decision of any Governmental Body, or to encourage the recipient to breach a duty of good faith or loyalty or the policies of his/her employer, in each case, in order to assist any member of the Company Group in obtaining or retaining business, or otherwise act in violation of any applicable Anti-Corruption Laws;
(ii)    violate any applicable Anti-Money Laundering Laws;
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(iii)    engage in any unlawful dealings or transactions with or for the benefit of any Sanctioned Person or otherwise violate Sanctions; or
(iv)    violate any applicable FDI Law.
(b)    The Company shall promptly notify the Members of (i) any allegations of misconduct by any member of the Company Group or any actions, suits or proceedings by or before any Governmental Body to which any member of the Company Group becomes a party, or to which the Company becomes aware that any Representative of the Company Group (in relation to such Representative’s actions for, or on behalf of, any member of the Company Group) is a party, in each case, relating to any material breach or suspected material breach of any applicable Anti-Corruption Laws, Anti-Money Laundering Laws, Sanctions or FDI Laws or (ii) any fact or circumstances of which it becomes aware that would reasonably be expected to result in a breach of this Section 9.4.
(c)    The Company and its Subsidiaries are subject to bona fide policies and procedures and a system of internal controls reasonably designed to ensure compliance by the Company, its Subsidiaries, their respective Representatives (in their capacity as such) and Affiliates with Anti-Corruption Laws, Anti-Money Laundering Laws, Sanctions and FDI Laws.
(d)    Each Manager and Board Observer may confer with the Member that appointed such Manager and/or Board Observer regarding any allegations of misconduct by any member of the Company Group relating to any breach or suspected breach of any applicable anti-terrorism Laws, Anti-Corruption Laws, Anti-Money Laundering Laws, Sanctions or FDI Laws.
(e)    Each Member shall, and shall use its commercially reasonable efforts to ensure that its Representatives in the course of their actions for, or on behalf of, such Member or its Affiliates, comply in all respects with all Anti-Corruption Laws, Anti-Money Laundering Laws and FDI Laws applicable to such Persons.
Section 9.5    Non-Solicit. Without the prior written consent of the Company, for so long as the Investor Member owns Membership Interests and for eighteen months thereafter, the Investor Member shall not, shall cause its Affiliates not to, and shall use its reasonable best efforts to ensure that other Persons in which it is invested do not, solicit for employment, hire or engage as a consultant any officer or a managing director or more senior-level employee of any member of the AEP Outside Group or the Company Group with whom the Investor Member has had contact with in connection with being a Member; provided that this Section 9.5 shall not prohibit any Person from issuing general public solicitations not specifically targeted at such Persons or from hiring any Person responding to such general solicitations. Notwithstanding anything to the contrary, in no event will this Section 9.5 apply to any portfolio company of any fund managed by or Affiliated with KKR or its Affiliates or PSP or its Affiliates unless, and solely to the extent that, Investor Member is an Affiliate of any such Person and expressly directs or encourages such portfolio company to take the prohibited actions set forth in this Section 9.5.
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Section 9.6    Confidentiality.
(a)    Each Member shall, and shall direct its Representatives to, keep confidential and not divulge any information (including all budgets, business plans and analyses) concerning the Company and its Subsidiaries, including their respective assets, business, operations, financial condition and prospects, that is disclosed by or on behalf of the Company on or after the date hereof (“Confidential Information”), and to use such Confidential Information only in connection with the operation of the Company and its Subsidiaries or such Member’s administration of its investment in the Company; provided that nothing herein shall prevent any Member (or Representative or other Person entitled to receive Confidential Information hereunder) from disclosing such Confidential Information (i) upon the Order of any court or administrative agency, (ii) upon the request or demand of any Governmental Body having jurisdiction over such party, (iii) to the extent compelled by legal process or required or requested pursuant to subpoena, interrogatories or other discovery requests or any other legal, judicial or administrative process or, in the advice of counsel, as required by Law, (iv) to the extent requested or required by the applicable regulatory authorities or self-regulatory organizations having supervisory jurisdiction over a Member, KKR, PSP, such Person’s Affiliates, Representatives or current or bona fide potential debt or equity financing sources of the foregoing during the course of any regulatory audit or examination, (v) to the other Parties, (vi) to such party’s Representatives or current or bona fide potential debt or equity financing sources that in the reasonable judgment of such party need to know such Confidential Information, (vii) in the case of the AEP Member, to its Affiliates, (viii) in the case of Investor Member, (A) to its Affiliates, KKR and PSP, KKR’s and PSP’s Affiliates, and Representatives of the foregoing and (B) to limited partners and other investors of investment funds or other investment vehicles controlled, advised or managed by an either KKR or PSP or their respective Affiliates in connection with disclosure to their investors in the ordinary course of business or current or bona fide potential debt or equity financing sources (ix) to any current or bona fide potential debt and equity financing sources (and any such financing source’s Representatives) in connection with a proposed Transfer of Membership Interests from a Member or proposed Debt Financing so long as such Person agrees to be bound by the provisions of this Section 9.6 as if a Member; provided, further, that in the case of clauses (i), (ii) or (iii), such Member shall, to the extent legally permissible, notify the other Parties of the proposed disclosure as far in advance of such disclosure as practicable and use reasonable efforts to ensure that any Confidential Information so disclosed is accorded confidential treatment, when and if available.
(b) The restrictions in Section 9.6(a) shall not apply to information that (i) is or becomes generally available to the public other than as a result of a disclosure by a Member or any of its Representatives in violation of this Agreement, (ii) is or becomes available to a Member or any of its Representatives on a non-confidential basis prior to its disclosure to the receiving Member and any of its Representatives, (iii) is or has been independently developed or conceived by such Member or its Affiliates without use of the Company’s or any of its Subsidiaries’ Confidential Information or (iv) becomes available to the receiving Member or any of its Representatives on a non-confidential basis from a source other than the Company or any of its Subsidiaries, any other Party or any of their respective Representatives; provided that such source is not known by the recipient of the information to be bound by a confidentiality agreement with the disclosing party or any of its Representatives with respect to such information.
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(c)    Each Party shall inform any Representatives or other permitted Person to whom it provides Confidential Information that such information is confidential and instruct them (i) to keep such Confidential Information confidential and (ii) not to disclose Confidential Information to any Third Party (other than those Persons to whom such Confidential Information has already been disclosed in accordance with the terms of this Agreement). The disclosing Party shall be responsible for any breach of this Section 9.6 by its Representative or other permitted Person to whom the Confidential Information is disclosed.
(d)    The restrictions in Section 9.6(a) shall not restrict any Member and its Affiliates from disclosing any Confidential Information required to be disclosed under applicable securities Laws or the rules of any stock exchange on which any of their securities are traded.
(e)    Notwithstanding anything in this Section 9.6, no Member shall disclose Confidential Information to a Representative or any Affiliate if such disclosure would be inconsistent with the FERC Standards of Conduct at 18 C.F.R. Part 358 or the FERC affiliate restrictions at 18 C.F.R. § 35.39 and each Member shall instruct any Representatives receiving Confidential Information regarding their obligations to protect Confidential Information from disclosure in a manner that could violate the FERC Standards of Conduct at 18 C.F.R. Part 358 or the FERC affiliate restrictions at 18 C.F.R. § 35.39.
(f)    Notwithstanding anything herein to the contrary, the provisions of this Section 9.6 shall survive the termination of this Agreement for a period of three years and, with respect to each Member, shall survive for a period of two years following the date son which such Member is no longer a Member. The provisions of this Section 9.6 shall supersede the provisions of any non-disclosure agreements entered into by the Company (or its Affiliates, including the AEP Member) and any of the Members (or their respective Affiliates) with respect to the transactions contemplated hereby or by the Contribution Agreement prior to the Effective Date.
Section 9.7    Expenses. Except as otherwise expressly provided herein, all costs and expenses, including fees and disbursements of Representatives and other Advisors, incurred in connection with this Agreement and with the continuing relationship between the Company and its Members, and among any of them, shall be paid by the Party incurring such costs and expenses (and for the avoidance of doubt, no such expenses incurred by the AEP Outside Group in respect of the AEP Member shall be allocated to the Company Group).
Section 9.8    Corporate Transparency Act Compliance. Each Member shall promptly, but within not more than five Business Days: (a) following reasonable request from the Company, provide to the Company any information reasonably necessary for the Company to comply with the CTA and (b) notify the Company of any change or inaccuracy in or to any information provided to the Company pursuant to Section 9.8(a) (other than an immaterial change that could not reasonably be expected to affect the Company’s compliance with the CTA).
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Section 9.9    Obligations in Respect of Financings.
(a)    Subject to Section 9.9(b), during the term of this Agreement, the AEP Member, the Company and the Company’s Subsidiaries shall cooperate with (and shall cause their Affiliates to cooperate with) Investor Member, its Affiliates and its controlling or managing direct and indirect equityholders as reasonably requested by the Investor Member in connection with any Debt Financing. Such cooperation shall include (i) providing to Investor Member its Affiliates and its controlling or managing direct and indirect equityholders such information as may be reasonably necessary in connection with the Debt Financing, and (ii) taking such other actions as are reasonably requested by the Investor Member to facilitate the consummation of any Debt Financing.
(b)    Notwithstanding anything in Section 9.9(a) or this Agreement to the contrary, the cooperation requested by the Investor Member pursuant to Section 9.9(a) shall not (i) unreasonably interfere with the normal business operations of the AEP Member, the Company or any of their respective Affiliates, or (ii) require the AEP Member, the Company or any of their respective Affiliates to (A) pay any commitment or other similar fee, (B) have or incur any liability or obligation in connection with any Debt Financing, including under any agreement or any document related to any Debt Financing, (C) commit to taking any action (including entering into any Contract) or to otherwise execute any document, agreement, certificate or instrument in connection with any Debt Financing or (D) take any action that would conflict with, violate or breach or result in a violation or breach of or default under any Contract, this Agreement or any other document contemplated hereby or any Law or regulatory requirements. In no event shall the AEP Member, the Company or any of their respective Affiliates be required to provide any record or information that the Company is not obligated to provide to the Investor Member pursuant to Section 9.1(b).
ARTICLE X
TAX MATTERS
Section 10.1    Tax Classification. The Parties intend that the Company be classified as a corporation for U.S. federal income (and applicable state and local) Tax purposes, and Internal Revenue Service Form 8832 has been properly filed electing such classification (which election was effective as of the date of the Company’s formation).
Section 10.2 Tax Matters Shareholder. The AEP Member is hereby designated the “Tax Matters Shareholder” of the Company and its Subsidiaries. Except as otherwise provided in this Agreement (including Section 8.1(b)), the Tax Matters Shareholder may, in its reasonable discretion, make or refrain from making any Tax elections allowed under applicable Law for the Company or any of its Subsidiaries. The Tax Matters Shareholder shall prepare and file or cause to be prepared and filed any Tax Return required to be filed by or with respect to the Company or its Subsidiaries. Notwithstanding any other provision of this Agreement, the Tax Matters Shareholder shall be entitled to control in all respects, and neither the Investor Member nor its Affiliates shall have the right to participate in, any Tax audits, examinations or other proceedings by any taxing authority of any Governmental Body with respect to any Tax Return of the Company or any of its Subsidiaries or any member of the AEP Outside Group.
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The Tax Matters Shareholder shall keep the Investor Member reasonably informed of any action relating to Taxes required to be taken or which may be taken by the Tax Matters Shareholder with respect to the Company or any of its Subsidiaries to the extent such action could reasonably be expected to have an adverse impact on the tax liability or tax position of the Investor Member or a material impact on the tax liability or tax position of the Company or any of its Subsidiaries (including any amount for which the Company or any of its Subsidiaries would be responsible for under the Tax Allocation Agreement (or any amendment thereof)).
Section 10.3    Tax Allocation Agreement. The Company shall enforce its rights under the Tax Allocation Agreement (or any amendment thereof), including any rights to receive payments or indemnification, or any recourse or remedies thereunder. The Tax Matters Shareholder shall (i) keep the Investor Member informed in advance of any payments to be received or made by the Company and its Subsidiaries pursuant to the Tax Allocation Agreement (or any amendment thereof), (ii) reasonably consult with the Investor Member prior to the Company paying or receiving any amounts under the Tax Allocation Agreement (or any amendment thereof), and (iii) provide any information reasonably requested by the Investor Member with respect thereto.
Section 10.4    Cooperation. The Investor Member shall, and shall cause its Affiliates to, provide to the AEP Member and its Subsidiaries (including the Company and its Subsidiaries), and the AEP Member and the Company shall, and shall cause their Affiliates to, provide to the Investor Member, in each case, such cooperation, documentation and information as any of them reasonably may request in connection with (a) filing any Tax Return, amended Tax Return or claim for refund, (b) determining a liability for Taxes or amounts due under the Tax Allocation Agreement (or any amendment thereof) or (c) preparing for or conducting any Tax audits, examinations or other proceedings by any Governmental Body.
Section 10.5 Withholding. The Company may withhold and pay over to the United States Internal Revenue Service (or any other relevant Tax authority) such amounts as it is required to withhold or pay over, pursuant to the Code or any other applicable Tax Law, on account of a Member, including in respect of distributions made pursuant to Section 5.2 or Section 5.3, and, for the avoidance of doubt, the amount of any such distribution or other payment to a Member shall be net of any such withholding; provided, that prior to any such withholding, the Company shall provide at least five days’ written notice of such withholding to the applicable Member and shall cooperate in good faith with such Member to reduce or eliminate any such withholding. To the extent that any amounts are so withheld and paid over, such amounts shall be treated as paid to the Person(s) in respect of which such withholding was made. To the extent that a Member claims to be entitled to a reduced rate of, or exemption from, a withholding Tax pursuant to an applicable income Tax treaty, or otherwise, such Member shall furnish the Company with such information and forms as such Member may be required to complete where necessary to comply with any and all Laws and regulations governing the obligations of withholding Tax agents, and the Company shall apply such reduced rate of, or exemption from, withholding Tax as reflected on such information and forms that have been provided by such Member. Each Member agrees that if any information or form provided pursuant to this Section 10.5 expires or becomes obsolete or inaccurate in any respect, such Member shall update such form or information.
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Section 10.6    Certain Representations and Warranties. Each Member represents and warrants that any such information and forms described in Section 10.5 and furnished by such Member shall be true and accurate to such Member’s knowledge and agrees to indemnify the Company from any and all damages, costs and expenses resulting from the filing of inaccurate or incomplete information or forms relating to such withholding Taxes.
Section 10.7    Intended Tax Treatment. Each of the Parties hereby acknowledges that the transactions contemplated hereby and those other transactions that were contemplated under the Contribution Agreement were or are being structured by the Parties in a manner to preserve the status of the Company as a member of the “affiliated group” (as defined in Section 1504(a) of the Code) of which AEP Parent is the common parent and to enable AEP Parent to include the Company in its U.S. consolidated group. If the AEP Member determines, based on the advice of counsel, that following the Closing (as defined in the Contribution Agreement), there have been any legislative amendments in the applicable Tax consolidation rules, or changes to the administrative or judicial interpretation thereof, that would reasonably be expected to impair the foregoing treatment, the AEP Member will have the option, upon written notice to the Investor Member and the Company to cause alterations to the governance and ownership structure of the Company, including amendments to this Agreement (subject to Section 13.10), to the minimum extent necessary to preserve the intended Tax consolidation (any such changes, “Tax-Driven Changes”). The AEP Member will consult with the Investor Member in good faith with respect to any such Tax Driven Changes and will provide a draft of any such Tax Driven Changes to the Investor Member for review. The AEP Member shall cooperate with the Investor Member to appropriately compensate the Investor Member for any loss in the Fair Market Value of its Membership Interests resulting from such Tax Driven Changes.
ARTICLE XI
LIABILITY; EXCULPATION; INDEMNIFICATION
Section 11.1    Liability; Member Duties. The debts, obligations and liabilities of the Company, whether arising in contract, tort or otherwise, shall be solely the debts, obligations and liabilities of the Company, and no Covered Person shall be obligated personally for any such debt, obligation or liability of the Company solely by reason of being a Covered Person. Each Member acknowledges and agrees that each Member, in its capacity as a Member, may decide or determine any matter subject to the approval of such Member pursuant to any provision of this Agreement in the sole and absolute discretion of such Member, and in making such decision or determination such Member shall have no duty, fiduciary or otherwise, to any other Member or to the Company Group, it being the intent of all Members that such Member, in its capacity as a Member, has the right to make such determination solely on the basis of its own interests.
Section 11.2 Exculpation. To the fullest extent permitted by applicable Law, no Covered Person shall be liable to the Company or any other Covered Person for any loss, damage or claim incurred by reason of any act or omission performed or omitted by such Covered Person in good faith on behalf of the Company and in a manner reasonably believed to be within the scope of the authority conferred on such Covered Person by this Agreement, except that a Covered Person shall be liable for any such loss, damage or claim incurred by reason of such Covered Person’s fraud, gross negligence or willful misconduct.
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Section 11.3    Indemnification. The Company shall indemnify, defend and hold harmless any Person who was or is a party or is threatened to be made a party to any threatened, pending or completed actions, suits or proceedings by reason of the fact that such Person is or was a Manager or officer of the Company, or is or was a Manager or officer of the Company serving at the request of the Company as a manager, director, officer or agent of another limited liability company, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees), judgments, settlements, penalties and fines actually and reasonably incurred by him or her in connection with the defense or settlement of such, action, suit or proceeding if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the Company; and, with respect to any criminal action or proceeding, either he or she had reasonable cause to believe such conduct was lawful or no reasonable cause to believe such conduct was unlawful.
Section 11.4    Authorization. To the extent that such present or former Manager or officer of the Company has been successful, on the merits or otherwise, in the defense of any action, suit or proceeding referred to in Section 11.3, or in the defense of any claim, issue or matter therein, the Company shall indemnify him or her against expenses (including attorneys’ fees) actually and reasonably incurred by him or her in connection therewith. Any other indemnification under Section 11.3 shall be made by the Company only as authorized in the specific case, upon a determination that indemnification of the present or former Manager or officer is permissible in the circumstances because such present or former Manager or officer has met the applicable standard of conduct. Such determination shall be made, with respect to a Person who is a Manager or officer at the time of such determination, (a) by a majority vote of the Managers who are not parties to such action, suit or proceeding, even with less than a quorum, or (b) if there are no such Managers, or if such Managers so direct, by independent legal counsel in a written opinion, or (c) by the Members. Such determination shall be made, with respect to former Managers and officers, by any Person or Persons having the authority to act on the matter on behalf of the Company.
Section 11.5    Reliance on Information. For purposes of any determination under Section 11.3, a present or former Manager or officer of the Company shall be deemed to have acted in good faith and have otherwise met the applicable standard of conduct set forth in Section 11.3 if his or her action is based on the records or books of account of the Company or on information supplied to him or her by the officers of the Company in the course of his or her duties, or on the advice of legal counsel for the Company or on information or records given or reports made to the Company by an independent certified public accountant or by an appraiser or other expert selected with reasonable care by the Company. The provisions of this Section 11.5 shall not be deemed to be exclusive or to limit in any way the circumstances in which a present or former Manager or officer of the Company may be deemed to have met the applicable standard of conduct set forth in Section 11.3.
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Section 11.6    Advancement of Expenses. Expenses (including reasonable attorneys’ fees) incurred by the present or former Manager or officer of the Company in defending any civil, criminal, administrative or investigative action, suit or proceeding may be paid by the Company as authorized in the specific case in the same manner described in Section 11.4, upon receipt of a written affirmation of the present or former Manager or officer that he or she has met the standard of conduct described in Section 11.3 and upon receipt of a written undertaking by or on behalf of him or her to repay such amount if it shall ultimately be determined that he or she did not meet the standard of conduct, and a determination is made that the facts then known to those making the determination shall not preclude indemnification under this Article XI.
Section 11.7    Non-Exclusive Provisions. The indemnification and advancement of expenses provided by, or granted pursuant to, this Article XI shall not be deemed exclusive of any other rights to which those seeking indemnification or advancement of expenses may be entitled. The Company hereby acknowledges that certain of its Managers and certain of its Members and the direct and indirect equityholders therein or owners thereof (the “Fund Indemnitees”) may have rights to indemnification, advancement of expenses and/or insurance with respect to their service on the Board (collectively, the “Fund Indemnitors”). The Company hereby agrees: (a) that it is the indemnitor of first resort (i.e., its obligations to the Fund Indemnitees are primary and any obligation of the Fund Indemnitors to advance expenses or to provide indemnification for the same expenses or liabilities incurred by the Fund Indemnitees are secondary) and (b) that it irrevocably waives, relinquishes and releases the Fund Indemnitors from any and all claims against the Fund Indemnitors for contribution, subrogation or any other recovery of any kind in respect thereof, except to the extent that a Fund Indemnitee breaches its undertaking to repay advanced expenses as provided in Section 11.6. The Company further agrees that no advancement or payment by the Fund Indemnitors on behalf of the Fund Indemnitees with respect to any claim for which the Fund Indemnitees have sought indemnification from the Company shall affect the foregoing and that the Fund Indemnitors shall have a right of contribution and/or be subrogated to the extent of such advancement or payment to all of the rights of recovery of the Fund Indemnitees against the Company.
Section 11.8    Survival of Indemnification and Advancement of Expenses. The indemnification and advancement of expenses provided by, or granted pursuant to, this Article XI shall, continue as to a Person who has ceased to be a Manager or officer of the Company and shall inure to the benefit of his or her heirs, executors and administrators and no amendment, modification or supplement of this Section 11.8 shall impair the rights of any Covered Person related to or affiliated with any Investor Member without the Investor Member’s prior written consent.
Section 11.9    Limitations. Notwithstanding anything contained in this Article XI to the contrary, the Company shall not be obligated to indemnify any Manager or officer (or his or her heirs, executors or personal or legal representatives) or advance expenses in connection with a proceeding (or part thereof) initiated by such Person unless such proceeding (or part thereof) was authorized or consented to by the Board.
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ARTICLE XII
REPRESENTATIONS AND WARRANTIES
Section 12.1    Members Representations and Warranties. Each Member hereby represents and warrants, severally and not jointly, to the Company and to the other Member as follows:
(a)    Such Member is a company duly organized, validly existing and in good standing under the Laws of its jurisdiction of incorporation or formation, as applicable, with full power and authority to enter into this Agreement and perform all of its obligations hereunder.
(b)    The execution and delivery of this Agreement by such Member, and the performance by such Member of its obligations hereunder, have been duly and validly authorized by all requisite action by such Member, and no other proceedings on the part of such Member are necessary to authorize the execution, delivery or performance of this Agreement by such Member.
(c)    This Agreement has been duly and validly executed and delivered by such Member, and, assuming that this Agreement is a valid and binding obligation of the other Parties, this Agreement constitutes a valid and binding obligation of such Member, enforceable against such Member in accordance with its terms, except as limited by the application of bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium or other Laws relating to or affecting creditors’ rights or general principles of equity.
(d)    The execution and delivery by such Member of this Agreement, and the performance by such Member of its obligations hereunder, does not (i) violate or breach its Organizational Documents, (ii) violate any applicable Law to which such Member is subject or by which any of its assets are bound, or (iii) result in any breach of or constitute a default (or an event that, with notice or lapse of time or both, would become a default) under any Contract to which such Member is a party or by which any of its assets are bound.
ARTICLE XIII
MISCELLANEOUS
Section 13.1 Notices. Except as otherwise expressly provided herein, all notices, demands and other communications to be given or delivered under or by reason of the provisions of this Agreement shall be in writing and shall be deemed to have been given (a) when personally delivered, (b) when transmitted by electronic mail (unless if transmitted after 5:00 p.m. Eastern time or other than on a Business Day, then on the next Business Day) to the address specified below in which case such notice shall be deemed to have been given when the recipient transmits manual written acknowledgment of successful receipt, which the recipient shall have an affirmative duty to furnish promptly after successful receipt, (c) when sent by internationally-recognized courier in which case it shall be deemed to have been given at the time of actual recorded delivery, or (d) the third Business Day following the day on which the same is sent by certified or registered mail, postage prepaid, in each case, to the respective Party at the number, electronic mail address or street address, as applicable, set forth below, or at such other number, electronic mail address or street address as such Party may specify by written notice to the other Party.
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Notices to the Investor Member:
Olympus BidCo L.P.
30 Hudson Yards, Suite 7500
New York, New York 10001
Attention:     Kathleen Lawler
        Louis-Éric Bonin
Email:         Kathleen.Lawler@kkr.com
        LEBonin@investpsp.ca
and
Public Sector Pension Investment Board
1250 René-Lévesque Boulevard West
Suite 1400
Montréal, Québec
Canada H3B 5E9
Attention:     Louis-Éric Bonin
E-mail:        projectskyfall@investpsp.ca
legalnotices@investpsp.ca

and
Kohlberg Kravis Roberts & Co. L.P.
30 Hudson Yards, Suite 7500
New York, New York 10001
Attention: General Counsel
E-mail: generalcounsel@kkr.com

with copies to (which shall not constitute notice):
Simpson Thacher & Bartlett LLP
600 Travis Street, Suite 5400
Houston, TX 77002
Attention:    Breen Haire
Shamus Crosby
Email:        breen.haire@stblaw.com
shamus.crosby@stblaw.com
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Notices to the AEP Member or the Company:
AEP Transmission Company, LLC
c/o American Electric Power Service Corporation
1 Riverside Plaza
Columbus, OH 43215
Attention:     Robert W. Bradish
Email:         rwbradish@aep.com
        legalnotices@AEP.com
with a copy to (which shall not constitute notice):
Morgan, Lewis & Bockius LLP
101 Park Ave
New York, NY 10178-0060
Attention:    John G. Klauberg
        Michael E. Espinoza
        Spencer A.G. Curtis
Email:         john.klauberg@morganlewis.com
michael.espinoza@morganlewis.com
spencer.curtis@morganlewis.com
Section 13.2    Assignment. This Agreement and all of the provisions hereof shall be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns; provided that neither Member, nor the Company, shall purport to assign or Transfer all or any of its rights or obligations under this Agreement nor grant, declare, create or dispose of any right or interest in this Agreement in whole or in part except with respect to a Transfer in accordance with the terms of this Agreement, and any attempted or purported assignment hereof not in accordance with the terms hereof shall be void ab initio.
Section 13.3    Waiver of Partition. Each Member hereby waives any right to partition of the Company property.
Section 13.4    Further Assurances. From and after the Effective Date, from time to time, as and when requested by any Party and at such Party’s expense, any other Party shall execute and deliver, or cause to be executed and delivered, all such documents and instruments and shall take, or cause to be taken, all such further or other actions as such requesting Party may reasonably deem necessary or desirable to carry out the purposes and intent of this Agreement.
Section 13.5    Third Party Beneficiaries. Except as otherwise expressly provided herein, nothing expressed or referred to in this Agreement shall be construed to give any Person other than the Parties any legal or equitable right, remedy or claim under or with respect to this Agreement or any provision of this Agreement; provided, that Covered Persons are express third party beneficiaries of Article XI.
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Section 13.6    Parties in Interest. This Agreement shall inure to the benefit of, and be binding upon, the Parties and their respective successors, legal representatives and permitted assigns.
Section 13.7    Severability. If any term, provision, covenant or restriction contained in this Agreement is held by a court of competent jurisdiction or other authority to be invalid, void, unenforceable or against its regulatory policy, the remainder of the terms, provisions, covenants and restrictions contained in this Agreement shall remain in full force and effect and shall in no way be affected, impaired or invalidated, and, to the extent permitted and possible, any invalid, void or unenforceable term shall be deemed replaced by a term that is valid and enforceable and that comes closest to expressing the intention of such invalid, void or unenforceable term.
Section 13.8    Construction. The language used in this Agreement shall be deemed to be the language chosen by the Parties to express their mutual intent, and no rule of strict construction shall be applied against any Person. The headings of the sections and paragraphs of this Agreement have been inserted for convenience of reference only and shall in no way restrict or otherwise modify any of the terms or provisions hereof.
Section 13.9    Complete Agreement. This Agreement (including any schedules thereto), constitutes the entire agreement of the Parties hereto with respect to the subject matter hereof and thereof and supersedes any prior understandings, agreements or representations by or among the Parties hereto or Affiliates thereof, written or oral, to the extent they relate in any way to the subject matter hereof.
Section 13.10 Amendment; Waiver. Subject to Article VIII, neither this Agreement nor any other Organizational Document of the Company may be amended (whether by merger or otherwise) except in a written instrument signed by Members owning at least a majority of the Membership Interests; provided, that (a) except for any Tax-Driven Changes being implemented in accordance with Section 10.7, the prior written consent of any Member shall be required in respect of any such proposed modification, alteration, supplement or amendment that would have a material disproportionate adverse impact on that Member (in its capacity as a Member) as compared to the other Members (in their capacity as Members), (b) except for any Tax-Driven Changes being implemented in accordance with Section 10.7, the prior written consent of the Investor Member shall be required to modify, alter, supplement or amend any provision of this Agreement or any other Organizational Document of the Company (unless such modification, alteration, supplement or amendment would not have an adverse impact on the Investor Member), and (c) notwithstanding anything in this Agreement to the contrary, Article V may not be amended other than by a written instrument signed by the Investor Member. In the event that the Company issues Membership Interests to one or more Third Parties pursuant to Section 5.1(c) or Section 7.1 or the Investor Member directly Transfers any Membership Interests to a Person that is not a Permitted Transferee of the Investor Member in accordance with the terms of this Agreement, the Members and the Company shall negotiate in good faith to amend this Agreement to the extent reasonably necessary to reflect such additional or substitute Members. Any amendment or revision to Schedule 1 that is made by an officer solely to reflect information regarding Members or the Transfer or issuance of Membership Interests made in accordance with the terms of this Agreement shall not be considered an amendment to this Agreement and shall not require any Board or Member approval.
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Any failure or delay on the part of any Party in exercising any power or right hereunder shall not operate as a waiver thereof, nor shall any single or partial exercise of any such right or power preclude any other or further exercise thereof or the exercise of any other right or power hereunder or otherwise available at law or in equity.
Section 13.11    Governing Law. This Agreement, and any claim, action, suit, investigation or proceeding of any kind whatsoever, including a counterclaim, cross-claim or defense, regardless of the legal theory under which such liability or obligation may be sought to be imposed, whether sounding in contract or tort, or whether at law or in equity, or otherwise under any legal or equitable theory, that may be based upon, arising out of or related to this Agreement or the negotiation, execution or performance of this Agreement or the transactions contemplated hereby shall be governed by and construed in accordance with the internal Laws of the State of Delaware applicable to agreements executed and performed entirely within such State without regards to conflicts of law principles of the State of Delaware or any other jurisdiction that would cause the Laws of any jurisdiction other than the State of Delaware to apply.
Section 13.12    Specific Performance. The Parties agree that irreparable damage, for which monetary relief, even if available, shall not be an adequate remedy, would occur in the event that any provision of this Agreement is not performed in accordance with its specific terms or is otherwise breached. It is accordingly agreed that (a) the Parties shall be entitled to seek an injunction or injunctions, specific performance or other equitable relief to prevent breaches of this Agreement and to enforce specifically the terms and provisions hereof without proof of damages or otherwise, this being in addition to any other remedy to which they are entitled under this Agreement, and (b) the right of specific performance and other equitable relief is an integral part of this Agreement and the business and legal understandings between the Members with respect to the Company, and without that right, none of the Members would have entered into this Agreement. The Parties acknowledge and agree that any Party pursuing an injunction or injunctions or other Order to prevent breaches of this Agreement and to enforce specifically the terms and provisions of this Agreement in accordance with this Section 13.12 shall not be required to provide any bond or other security in connection with any such Order. The remedies available to the Parties pursuant to this Section 13.12 shall be in addition to any other remedy to which they may be entitled at law or in equity, and the election to pursue an injunction or specific performance shall not restrict, impair or otherwise limit any Party from seeking to collect or collecting damages. Each of the Parties agrees that it shall not oppose the granting of an injunction, specific performance and other equitable relief on the basis that any other Party has an adequate remedy at law or that any award of specific performance is not an appropriate remedy for any reason at law or in equity.
Section 13.13    Escalation; Arbitration.
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(a) In connection with any dispute (other than, for the avoidance of doubt, a dispute arising related to the discretionary exercise of any right of a Member (including consent rights pursuant to Article VIII) granted to a Member, the Company or to the Board under, and in accordance with the terms of, this Agreement), controversy or claim among the Members relating to or arising out of this Agreement, the Members will use their reasonable efforts to resolve such dispute within 30 days. If the dispute has not been resolved within such 30 day period, the Members will escalate the dispute to the respective senior officers, who will meet to discuss and use their reasonable efforts to resolve the dispute. If the Members remain unable to resolve the dispute within 30 days of the initial meeting of the senior officers or such later date as the Members subject to such dispute may agree, such dispute shall be finally settled by binding arbitration administered by the American Arbitration Association (“AAA”) utilizing its Commercial Arbitration Rules in effect as of the date the arbitration is commenced. The arbitration shall be conducted before a single arbitrator, if the Members can agree on the one arbitrator. If the Members cannot agree on a single arbitrator, there shall be a panel of three arbitrators with one chosen by each Member and the third arbitrator selected by the two Member-appointed arbitrators. If a Member fails to appoint an arbitrator within 30 days following a written request by another Member to do so or if the two Member-appointed arbitrators fail to agree upon the selection of a third arbitrator, as applicable, within 30 days following their appointment, the additional arbitrator shall be selected by the AAA pursuant to its applicable procedures. Each arbitrator shall be disinterested and have at least 20 years of experience with commercial matters. The arbitrator(s) shall have the power to award any appropriate remedy consistent with the objectives of the arbitration and subject to, and consistent with, all Laws and Orders applicable to the Company and its Subsidiaries (including, for the avoidance of doubt, the necessity of obtaining any requisite authorization, approval or consent of any Governmental Body necessary to implement the appropriate remedy). The decision of the one arbitrator or, if applicable, the majority of the three arbitrators shall be final and binding upon the Parties (subject only to limited review as required by applicable Law). Judgment upon the award of the arbitrator(s) may be entered in any court of competent jurisdiction or otherwise enforced in any jurisdiction in any manner provided by applicable Law. The losing Party shall pay the prevailing Party’s attorney’s fees and costs and the costs associated with the arbitration, including expert fees and costs and the arbitrators’ fees and costs; provided, however, that each Party shall bear its own fees and costs until the arbitrator(s) determine which, if any, Party is the prevailing Party and the amount that is due to such prevailing Party.
(b)    All discussions, negotiations and proceedings under this Section 13.13, and all evidence given or discovered pursuant hereto, will be maintained in strict confidence by all Parties, except where disclosure is required by applicable Law, necessary to comply with any legal requirements of such Party or necessary or advisable in order for a Party to assert any legal rights or remedies, including the filing of a complaint with a court or, based on the advice of counsel, such disclosure is determined to be necessary or advisable under applicable securities Laws or the rules of any stock exchange on which any of such Party’s securities are traded. Disclosure of the existence of any arbitration or of any award rendered therein may be made as part of any action in court for interim or provisional relief or to confirm or enforce such award.
(c) Any settlement discussions occurring and negotiating positions taken by any Party in connection with the procedures under this Section 13.13 will be subject to Rule 408 of the Federal Rules of Civil Procedure and shall not be admissible as evidence in any proceeding relating to the subject matter of this Agreement.
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(d)    The fact that the dispute resolution procedure specified in this Section 13.13 has been or may be invoked will not excuse any Party from performing its obligations under this Agreement, and during the pendency of any such procedure, all Parties must continue to perform their respective obligations in good faith. In addition, in no event shall the fact that this provision has been invoked and the pendency of the proceedings limit, suspend, delay or waive any other rights and remedies provided in this Agreement to any Member.
(e)    Notwithstanding the agreement to arbitrate contained in this Section 13.13, in the event that any Party wishes to seek a temporary restraining order, a preliminary or temporary injunction, or other injunctive relief in connection with any claim, demand, cause of action, dispute, controversy, or other matter arising out of or relating to this Agreement or the alleged breach thereof, whether such claim sounds in contract, tort, or otherwise, at law or in equity, under state or federal law, whether provided by statute or the common law, each Party shall have the right to pursue such injunctive relief in court, rather than by arbitration. The Parties agree that such action for a temporary restraining order, a preliminary or temporary injunction, or other injunctive relief may be brought in the state or federal courts of Delaware, or in any other forum in which jurisdiction is appropriate.
Section 13.14    Counterparts. This Agreement may be executed in counterparts, and any Party may execute any such counterpart, each of which when executed and delivered shall be deemed to be an original and all of which counterparts taken together shall constitute one and the same instrument. This Agreement shall become effective when each Party shall have received a counterpart hereof signed by the other Parties. The Parties agree that the delivery of this Agreement may be effected by means of an exchange of electronically transmitted signatures.
Section 13.15 Fair Market Value Determination. Upon request by any Member, so long as such Member holds a Percentage Interest greater than 4.9% (unless the Fair Market Value determination is in connection with a Put Sale, in which case the Investor Members or their Permitted Transferees participating in the Put Sale shall not be subject to any minimum Percentage Interest threshold to make such request), (x) with respect to Put Sales, within the times frames contemplated by Section 6.6 and (y) with respect to determination of Fair Market Value for all other matters, within five Business Days after receiving written notice of the Board’s determination in connection with any determination of Fair Market Value of Membership Interests or other assets under this Agreement (which determination shall be provided by the Company to each Member promptly following the making thereof), in each case, the Company shall select a nationally recognized independent valuation firm with no existing or prior business or personal relationship with any Member or any of its Affiliates in the three-year period immediately preceding the date of engagement pursuant to this Section 13.15 (the “Independent Evaluator”) to determine such Fair Market Value. Each of the Company and the requesting Member shall submit their view of the Fair Market Value of the Membership Interests or the relevant asset(s) to the Independent Evaluator (the Company’s view being the original determination by the Board), and each party will receive copies of all information provided to the Independent Evaluator by the other party.
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The Members shall request that the final Independent Evaluator’s determination of the Fair Market Value of such Membership Interests or asset(s) be set forth in a detailed written report addressed to the Company and the requesting Member within 30 days following the Company’s selection of such Independent Evaluator and such determination shall be final, conclusive and binding. In rendering its decision, the Independent Evaluator shall determine which of the positions of the Company and the requesting Member submitted to the Independent Evaluator is, in the aggregate, more accurate (which report shall include a worksheet setting forth the material calculations used in arriving at such determination), and, based on such determination, adopt either the Fair Market Value determined by the Company or the requesting Member. Any fees and expenses of the Independent Evaluator incurred in resolving the disputed matter(s) will be borne by the party whose positions were not adopted by the Independent Evaluator. Notwithstanding the foregoing, the Board’s determination of Fair Market Value under this Agreement shall be conclusive and relied upon by the Members in carrying out their obligations hereunder for any matter that, following determination of the Independent Evaluator, may be cured, unless and until the Independent Evaluator determines otherwise in accordance with this Section 13.15.
Section 13.16    Certain Definitions. As used in this Agreement, the following terms shall have the meanings ascribed to them below:
“Act” means the Delaware Limited Liability Company Act, as amended from time to time.
“Advisors” means, with respect to any Person, the accountants, attorneys, consultants, advisors, investment bankers, or other representatives of such Person.
“AEP Outside Group” means AEP Parent and its Subsidiaries, other than the Company Group.
“AEP Parent” means American Electric Power Company, Inc.
“AEP TransCo Note” means that certain promissory note dated December 30, 2024 payable by the Company to the AEP Member.
“AEP Transmission” means AEP Transmission Company, LLC (regardless of whether such Person remains the AEP Member).
“Affiliate” of any particular Person means any other Person controlling, controlled by or under common control with such particular Person, where “control” means the possession, directly or indirectly, of the power to direct the management and policies of a Person whether through the ownership of voting securities, Contract or otherwise. For purposes of this Agreement, any Person advised, managed or controlled by KKR or PSP shall be deemed to be an Affiliate of an Investor Member so long as KKR or PSP, respectively, directly or indirectly own equity interests in such Investor Member hereunder.
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“Anti-Corruption Laws” means (a) the U.S. Foreign Corrupt Practices Act of 1977, as amended; (b) the U.K. Bribery Act 2010, as amended; and (c) any other Law concerning or relating to bribery or corruption imposed, administered or enforced by any Governmental Body.
“Anti-Money Laundering Laws” means any Law concerning or relating to money laundering, any predicate crime to money laundering or any record keeping, disclosure or reporting requirements related to money laundering imposed, administered or enforced by any Governmental Body.
“Available Cash” means, for any applicable fiscal quarter, the cash flow generated from the business operations of the Company and its Subsidiaries in such fiscal quarter, less any amounts that the Board, as substantiated by written financial reports and forecasts, reasonably determines in good faith are necessary to be retained in order to (a) comply with covenants in respect of the Company Group Third Party Indebtedness, (b) maintain the Company’s and its Subsidiaries’ target regulatory capital structure and investment-grade credit metrics, and comply with any applicable Laws and Orders governing the regulatory capital structure of the Company Group (such retained amount, if any, to be determined assuming full funding of equity available to be called by the Company at such time from Mandatory Capital Contributions (unless an Event of Default pursuant to Section 4.1(c) has occurred and remains uncured in accordance with Section 4.2) and available debt capacity of the Company Group), (c) except with respect to maintaining the Company’s and its Subsidiaries’ target regulatory capital structure and related Laws and Orders governing the regulatory capital structure of the Company Group (which shall exclusively be governed by clause (b)), comply with applicable Law and Orders (such retained amount, if any, to be determined assuming full funding of equity available to be called by the Company at such time from Mandatory Capital Contributions (unless an Event of Default pursuant to Section 4.1(c) has occurred and remains uncured in accordance with Section 4.2) and available debt capacity of the Company Group), (d) permit the Company and its Subsidiaries to pay their obligations due as of such date or that are expected to become due in the next 90 days in the ordinary course of business (including making any required payments of principal or interest in satisfaction of Company Group Third Party Indebtedness but, unless an Event of Default pursuant to Section 4.1(c) has occurred and remains uncured in accordance with Section 4.2, excluding the funding of any capital expenditures) that cannot be satisfied on commercially reasonable terms by the Company Group’s available liquidity and (e) respond to an Emergency Situation. For the avoidance of doubt, the proceeds of the issuance of the Investor Member’s Membership Interests shall be excluded from the calculation of Available Cash (and may be held in a segregated sub account in the regulated money pool program of the AEP Outside Group).
“Business Day” means any day other than a Saturday, Sunday or a day on which banking institutions located in New York, New York are authorized by applicable Law to be closed.
“Change in Control” means (a) with respect to Investor Member, Investor Member ceasing to be controlled by either of or any combination of (i) any Person or Persons advised, managed or controlled by KKR or its Affiliates and (ii) any Person or Persons advised, managed or controlled by PSP or its Affiliates (provided that, for the avoidance of doubt, it shall not constitute a Change in Control with respect to Investor Member if Investor Member remains controlled by any combination of Persons described in clauses (i) and (ii) above) and (b) with respect to any other applicable Person, any person or group (within the meaning of Sections 13(d)(3) and 14(d)(2) of the Securities Exchange Act of 1934, as amended) at any time becoming the beneficial owner of 50% or more of the combined voting power of the voting securities of such Person.
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“Code” means the Internal Revenue Code of 1986, as amended.
“Commitment Year” has the meaning set forth in the ECLs.
“Company Group” means the Company and each of its Subsidiaries, collectively.
“Company Group Third Party Indebtedness” means the Indebtedness of any member of the Company Group then outstanding with a (a) Third Party or (b) member of the AEP Outside Group if the Indebtedness with such member is issued on the same economic terms as the Indebtedness of the AEP Outside Group then outstanding with a Third Party (excluding the regulated money pool program of the AEP Outside Group).
“Competitor” means any Person that, or through its Subsidiaries, is directly engaged in the transmission of electricity in the United States. Notwithstanding anything to the contrary, a Competitor shall not include any financial sponsors, investment fund, private equity funds, hedge funds, sovereign wealth funds, co-investment vehicles or similar investment vehicles or arrangements, even if such financial sponsor, investment fund, private equity funds, hedge funds, sovereign wealth funds, co-investment vehicles or similar investment vehicles or arrangements directly or indirectly owns equity in any Person that otherwise meets the definition of Competitor (however, for the avoidance of doubt, such investee that meets the definition of Competitor will continue to be considered a Competitor).
“Contract” means any written agreement, arrangement, commitment, indenture, instrument, purchase order, license or other binding agreement.
“Contribution Agreement” means the Contribution Agreement, dated January 9, 2025, by and among the Company, the AEP Member and the Investor Member.
“Contribution Agreement Purchase Price” means the amount of the Purchase Price (as defined in, and finally adjusted pursuant to, the Contribution Agreement) paid by the Investor Member (or its predecessors in interest) to the Company.
“Covered Person” means any (a) Member, any Affiliate of a Member or any officers, managers, directors, shareholders, partners, members, other equityholders, employees, representatives or agents of a Member or their respective Affiliates, (b) Manager, or (c) employee, officer or agent of the Company or its Affiliates.
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“Credit Rating” means, with respect to any Person, each of the ratings given to such Person’s senior, unsecured, non-credit enhanced, long-term debt obligations by S&P Global Ratings or Moody’s Investors Services, Inc., as applicable, and any successors thereto.
“Credit Support” means (a) an equity commitment letter on substantively the same terms as the ECLs or on terms substantively as favorable to the Company as the ECLs provided by a Person that is Financially Capable for an amount corresponding to the direct or indirect equity interest in the Company being Transferred, (b) a parent guaranty provided for the benefit of the Company by a Person that is Financially Capable for an amount corresponding to the direct or indirect equity interest in the Company being Transferred on terms and conditions reasonably acceptable to the Company (which reasonableness shall be determined solely with respect to the terms and conditions of such parent guaranty and not with respect to the counterparty thereto or any other facts or circumstances), (c) a customary letter of credit, with only administrative draw conditions, provided by a commercial bank or trust company for the benefit of the Company in an amount equal to the applicable ECL Annual Commitment Amount that corresponds to the direct or indirect equity interest in the Company being Transferred along with a Contract, on terms and conditions reasonably acceptable to the Company (which reasonableness shall be determined solely with respect to the terms and conditions of such Contract and not with respect to the counterparty thereto or any other facts or circumstances), requiring the annual update of such letter of credit for the applicable ECL Annual Commitment Amount, (d) a cash escrow amount for the benefit of the Company equal to the applicable ECL Annual Commitment Amount that corresponds to the direct or indirect equity interest in the Company being Transferred along with a Contract, on terms and conditions reasonably acceptable to the Company (which reasonableness shall be determined solely with respect to the terms and conditions of such Contract and not with respect to the counterparty thereto or any other facts or circumstances), requiring the annual update of such cash escrow amount for the applicable ECL Annual Commitment Amount or (e) cash collateral provided to the Company equal to the applicable ECL Annual Commitment Amount that corresponds to the direct or indirect equity interest in the Company being Transferred along with a Contract, on terms and conditions reasonably acceptable to the Company (which reasonableness shall be determined solely with respect to the terms and conditions of such Contract and not with respect to the counterparty thereto or any other facts or circumstances), requiring the annual update of such cash collateral amount for the applicable ECL Annual Commitment Amount.
“CTA” means the Corporate Transparency Act (31 U.S.C. § 5336), enacted as part of the National Defense Authorization Act for Fiscal Year 2021, as amended, and the rules and regulations promulgated thereunder.
“Debt Financing” means any debt financing incurred by or to be incurred by the Investor Member or any of its Affiliates (other than, for the avoidance of doubt, the Company or its Subsidiaries), the direct or indirect controlling or managing equityholders of Investor Member or any Affiliate of such equityholder, including the incurrence or refinancing of any loans or the issuance of any bonds, notes, debentures or hybrid securities that are or would be the obligations of such Persons.
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“Debt-to-Capital Ratio” means, with respect to any Person, the ratio of (a) the Indebtedness of such Person and its Subsidiaries to (b) the sum of (i) the Indebtedness of such Person and its Subsidiaries plus (ii) Member equity, capital stock (but excluding treasury stock and capital stock subscribed and unissued) and other equity accounts (including retained earnings and paid in capital but excluding accumulated other comprehensive income and loss) of such Person and its Subsidiaries, determined in accordance with GAAP or the accounting rules of FERC (including with respect to the Uniform System of Accounts under the Federal Power Act), as applicable.
“ECLs” means that certain (i) Equity Commitment Letter, dated as of the date hereof, by KKR Diversified Core Infrastructure Master Fund L.P., KKR Diversified Core Infrastructure Master Fund (A) SCSp, KKR Diversified Core Infrastructure Master Fund (B) SCSp and KKR Diversified Core Infrastructure Fund (SBS) L.P. for the benefit of the Company and (ii) Equity Commitment Letter, dated as of the date hereof, by Infra-PSP Canada Inc. for the benefit of the Company.
“ECL Aggregate Funded Amounts” means the cumulative amount of all capital contributions (but excluding any Excess Contributions that are distributed pursuant to Section 5.1(b)(i)) made by the Investor Member (or its predecessors in interest or direct Transferees) pursuant to the ECLs (or any replacement Credit Support thereof) in all calendar years. For the avoidance of doubt, in any given Commitment Year, all capital contributions (other than payment of the Contribution Agreement Purchase Price) made by Investor Member (or its predecessors in interests or direct Transferees) in such Commitment Year up to the ECL Annual Commitment Amount for such year shall be deemed to be amounts made pursuant to any or both ECLs (or any replacement Credit Support thereof), regardless of whether either ECL (or any replacement Credit Support thereof) was actually enforced or expressly called upon by the Company.
“ECL Annual Commitment Amount” means (i) from the Effective Date until the end of the first Commitment Year ending December 31, 2025, an amount equal to $137.4 million, prorated based on the remaining number of days in such Commitment Year from and including the Effective Date divided by 365 days, (ii) for the second Commitment Year ending December 31, 2026, an amount equal to $141.4 million and (iii) for each Commitment Year thereafter, an amount equal to the total cash distributions made to Investor Member (or, without duplication, its predecessors in interest or direct Transferees) pursuant to Section 5.2 during the prior Commitment Year.
“Emergency Expenditure” means amounts required to be incurred in direct and immediate response to an Emergency Situation in a manner that is consistent with general practices applicable to facilities used in the Company Business, but only to the extent such expenditures are reasonably designed to ameliorate the consequences, or an immediate threat of any of the consequences, of the issues set forth in the definition of “Emergency Situation.”
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“Emergency Situation” means, with respect to the business of the Company and its Subsidiaries, (a) any abnormal system condition or abnormal situation requiring immediate action to maintain system frequency, loading within acceptable limits or voltage or to prevent loss of firm load, material equipment damage or tripping of system elements that is reasonably likely to materially and adversely affect reliability of an electric system, (b) any other occurrence or condition that otherwise requires immediate action to prevent an immediate and material threat to the safety of Persons or the operational integrity of, or material damage to, any material assets of, or the business of the Company or its Subsidiaries, or (c) any other condition or occurrence requiring immediate implementation of emergency procedures as defined by the applicable transmission grid operator or transmitting utility.
“Encumber” means to place a Lien against.
“Excluded Membership Interests” means any Membership Interests or other equity interests in the Company issued in connection with:
(a)    any arrangement approved unanimously by the Board for the return of income or capital to the Members;
(b)    subject to Section 8.1(c), any equity split, equity dividend or any similar recapitalization; or
(c)    the commencement of any offering of Membership Interests or other equity interests of the Company or any of its Subsidiaries, pursuant to a registration statement filed in accordance with the United States Securities Act of 1933.
“Excluded Opportunity” means:
(a)    any “Target Project” or “Optional Project” (each as defined in the Transource Agreement for purposes of this clause (a)) required to be presented by any member of the AEP Outside Group to Transource pursuant to the exclusivity obligations of the members under the Transource Agreement; provided, that (i) if Transource, for any reason and in its sole discretion chooses not to pursue the development or acquisition of any Optional Project (as defined in the Transource Agreement) and (ii) a member of the AEP Outside Group is expressly permitted to pursue such Optional Project (as defined in the Transource Agreement) thereafter independently of Transource in accordance with the Transource Agreement, such Optional Project (as defined in the Transource Agreement) shall no longer be considered an “Excluded Opportunity” pursuant to this clause (a); or
(b)    any local reliability electric transmission project or related upgrade that is required by Law to be first offered to any incumbent electric transmission owner other than a member of the Company Group; provided, that if the incumbent electric transmission owner to which such project is offered chooses not to accept such project, such project shall no longer be considered an “Excluded Opportunity” pursuant to this clause (b).
“Existing OpCos” means Indiana Michigan Power Company and Ohio Power Company and any Affiliate of the AEP Member that is a successor thereto.
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“Fair Market Value” means, with respect to any asset (including equity interest), the price at which the asset would change hands between a willing buyer and a willing seller that are not affiliated parties, neither being under any compulsion to buy or to sell, and both having knowledge of the relevant facts and taking into account the full useful life of the asset. In valuing Membership Interests, no consideration of any control, liquidity or minority discount or premium shall be taken into account. Fair Market Value shall be determined by the Board in accordance with the foregoing, subject to Section 13.15 and, if applicable, Section 6.6.
“FDI Law” means any Law concerning or relating to foreign investment or national security imposed, administered or enforced by any Governmental Body.
“FERC” means the U.S. Federal Energy Regulatory Commission or any successor agency thereto.
“Financially Capable” means any Person that (a) is (i) Affiliated with or managed by an asset manager, fund manager or a fund advisor with “assets under management” (as such term is commonly defined in the private equity or investment fund industry) of at least $5,000,000,000, (ii) a Person with its equity interests listed on a nationally recognized stock exchange which has a market capitalization of at least $5,000,000,000 or (iii) a Person that based on its most recent audited balance sheet has at least $5,000,000,000 of assets; (b) if such Person or its ultimate parent company has a Credit Rating, has a Credit Rating of no less than “BBB-” from S&P Global Ratings or “Baa3” from Moody’s Investors Services, Inc.; and (c) is not a Prohibited Competitor.
“GAAP” means United States generally accepted accounting principles applied on a consistent basis during the periods involved.
“Governmental Body” means any national, foreign, federal, regional, state, local, municipal or other governmental authority of any nature (including any division, department, agency, commission or other regulatory body thereof) and any court or arbitral tribunal, including any governmental, quasi-governmental or non-governmental body administering, regulating or having general oversight over electricity, power or the transmission or transportation thereof, including any regional transmission operator, independent system operator and any market monitor thereof.
“Growth Commitment Amount” means one billion five hundred million dollars ($1,500,000,000).
“Indebtedness” means, with respect to any Person, (a) all indebtedness of such Person, whether or not contingent, for borrowed money or in respect of any loans or advances, (b) all other indebtedness of such Person evidenced by bonds, debentures, notes or other similar instruments or debt securities (excluding trade accounts payables constituting short term liabilities under GAAP), (c) the maximum amount of all direct or contingent obligations of such Person arising under letters of credit (including standby and commercial), bankers’ acceptances, bank guaranties, surety bonds and similar instruments, (d) all guarantees of the obligations of any other Person, (e) net obligations of such Person under any hedging arrangement, and (f) any accrued interest, premiums and penalties.
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“IRR” means, as of the consummation of a Drag-Along Sale, the actual pre-Tax annual rate of return of the Investor Member (specified as a percentage) taking into account only the following, on a cash-in, cash-out basis: (a) the cumulative amount of all capital contributions made to the Company by the Investor Member (or its predecessors in interest) in respect of such Membership Interests (but excluding any Excess Contributions that are distributed pursuant to Section 5.1(b)(i)) prior to such time plus the amount of the Contribution Agreement Purchase Price, and (b) all cash distributions to the Investor Member (or its predecessors in interest) on or before such date (but excluding any special distributions in respect of Excess Contributions pursuant to Section 5.1(b)(i)). The IRR will be calculated using the XIRR function in the most recent version of Microsoft Excel (or if such program is no longer available, such other software program for calculating the IRR as is reasonably determined by the Board), and will be based on the actual dates of funding of such capital contributions and the actual dates of receipt of such cash distributions and proceeds.
“KKR” means Kohlberg Kravis Roberts & Co. L.P.
“Law” means any law (statutory, common, or otherwise), rule, regulation, code or ordinance enacted, adopted, promulgated or applied by any Governmental Body, including all regulatory requirements emanating from state and federal regulators of the Company Group’s businesses and operations.
“Liabilities” means any and all liabilities or obligations, whether accrued, contingent, absolute or otherwise.
“Liens” means all liens, mortgages, deeds of trust, pledges, security interests, charges, claims, proxy, voting trust or transfer restriction under any stockholder or similar agreement.
“Losses” means any and all actual losses, damages, Liabilities, Taxes, claims, demands, causes of action, legal proceedings, Orders, remedies, obligations, assessments, awards, payments, costs and expenses, interest, penalties, fines, judgments and settlements.
“Member” means each of AEP Member and Investor Member, and any Person admitted as an additional member of the Company or a substitute member of the Company pursuant to the provisions of this Agreement, each in its capacity as a member of the Company.
“Membership Interests” means membership interests of the Company.
“MOIC” means, as of the consummation of a Drag-Along Sale, with respect to the Investor Member, the number resulting from the quotient of (i) all cash distributions to the Investor Member (or its predecessors in interest) on or before such date in respect of such Membership Interests (but excluding any special distributions in respect of Excess Contributions pursuant to Section 5.1(b)(i)) divided by (ii) the cumulative amount of all capital contributions made to the Company by the Investor Member (or its predecessors in interest) in respect of such Membership Interests (but excluding any Excess Contributions that are distributed pursuant to Section 5.1(b)(i)) prior to such time plus the amount of the Contribution Agreement Purchase Price.
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“New Securities” means any Membership Interests or other equity interests in the Company, other than any Excluded Membership Interests.
“OFAC” means the U.S. Office of Foreign Assets Control.
“Order” means any judgment, order, injunction, decree, ruling, writ or arbitration award of any Governmental Body or any arbitrator.
“Organizational Documents” means, with respect to any corporation, its articles or certificate of incorporation, memorandum or articles of association and by-laws or documents of similar substance; with respect to any limited liability company, its articles of association, articles of organization or certificate of organization, formation or association and its operating agreement or limited liability company agreement or documents of similar substance; with respect to any limited partnership, its certificate of limited partnership and partnership agreement or documents of similar substance; and with respect to any other entity, documents of similar substance to any of the foregoing.
“Percentage Interest” means, in respect of any Member, their relative ownership in the Membership Interests, expressed as a percentage, which shall be deemed to be equal to the number of Membership Interests that such Member owns divided by the total number of Membership Interests then outstanding.
“Permitted Transferee” means, with respect to the (a) AEP Member or the Investor Member, (i) a directly or indirectly wholly owned Subsidiary of such Member, (ii) an Affiliate of such Member of which such Member is, directly or indirectly, a wholly owned Subsidiary (an “Affiliate Parent”), (iii) an Affiliate of such Member that is a wholly owned Subsidiary of an Affiliate Parent and (b) with respect to the Investor Member, any Person that is an Affiliate of or is managed or advised by KKR or its Affiliates or PSP or its Affiliates, in each case of the foregoing clauses (a) and (b), so long as (i) any required authorization, approval or consent of all applicable Governmental Bodies in respect of such transfer has been received, and (ii) such transfer would not reasonably be expected to result in the consequences specified in either clause (i) or clause (ii) of Section 6.3(c).
“Persons” means an individual, a partnership, a corporation, a limited liability company, an association, a joint stock company, a trust, a joint venture, an unincorporated organization or a Governmental Body.
“Preemptive Right Share” means a ratio of (a) the number of Membership Interests held by such Member with Preemptive Rights, to (b) the total number of Membership Interests then outstanding immediately prior to the issuance of New Securities giving rise to the Preemptive Rights.
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“Prohibited Competitor” means any Competitor listed on Schedule 2, as may be updated from time to time in accordance with Section 6.3(b).
“Project Selection Guidelines” means the AEP Transmission Project Selection Guidelines of the AEP Outside Group, effective as of September 30, 2024, as may be amended from time to time subject to obtaining any required consent pursuant to Section 8.1(h); provided that, notwithstanding anything to the contrary contained in the Project Selection Guidelines, the Project Selection Guidelines shall be interpreted for all purposes of this Agreement without giving effect to “State Transcos” being wholly owned by (or being required to be wholly owned by) AEP Parent thereunder.
“Prudent Utility Practice” shall mean the practices, methods and acts (a) engaged in or approved by a significant portion of electric transmission-owning utilities in the United States during the relevant time period or (b) that, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, are reasonably expected to accomplish the desired result in a manner consistent with applicable Law, good business practices, reliability, safety, environmental protection, economy and expedience; provided that Prudent Utility Practice is not intended to be limited to optimum practices, methods or acts to the exclusion of all others but rather is intended to include a spectrum of acceptable practices, methods or acts generally accepted in the region during the relevant period in light of the circumstances.
“PSP” means Public Sector Pension Investment Board.
“Qualified Designee” means either (a) (i) with respect to the AEP Member, an employee or officer of AEP Member or any of its Affiliates and (ii) with respect to the Investor Member, an employee, officer, director or equivalent position of the Investor Member, any direct or indirect controlling or managing equityholder of Investor Member or any Affiliate of such equityholder (including in the case of any investment fund, private equity funds, hedge funds, sovereign wealth funds, co-investment vehicles or similar investment vehicles or arrangements, the general partner, managing member, asset manager, fund manager, fund advisor, management company or similar managing entity thereof) investing in, or managing, such direct or indirect equityholder (an “Investor Employee”) or (b) an individual with at least 10 years of management-level experience in the private sector electricity transmission, distribution and generation business; provided, that a “Qualified Designee” shall not include (i) with respect to the Investor Member, any manager, director, officer, employee or other Person affiliated with a Prohibited Competitor, (ii) any Person that is, or within 10 years prior to the Effective Date was, an employee or consultant of FERC, (iii) any Person who would require prior authorization from FERC under Section 305(b) of the Federal Power Act to serve as an Investor Manager and who has failed to comply with such FERC filing requirements and any Person who has failed to comply with the Standards of Conduct, functional separation, and other requirements that are then imposed by FERC with respect to that Person’s service as an Investor Manager (it being understood that, for the avoidance of doubt, no such person may be deemed to have failed to comply while any such filings, other submissions or other requirements are being prepared, processed or considered, except for interlocking authorizations under Section 305(b) of the Federal Power Act that require a FERC order prior to holding the interlocking positions); (iv)
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any Person convicted by a court or equivalent tribunal of any felony (or equivalent crime in the applicable jurisdiction) or of any misdemeanor (or equivalent crime in the applicable jurisdiction) that involves financial dishonesty or moral turpitude, or (v) solely in the case of an individual that is not an Investor Employee or an employee or officer of AEP Member or any of its Affiliates, any Person that would create a material regulatory or reputational risk to the Company based on a good-faith determination by the Board.
“Qualifying Core Assets” means assets utilized in connection with the conduct of the Company Business on which the Company reasonably expects (a) that it or its Subsidiaries will be eligible to include in the applicable rate base, and (b) to earn a return through rates approved by FERC (or such other Governmental Body that may then be applicable) that are commercially reasonable (to be determined by the Board in good faith) and are not otherwise inconsistent with applicable FERC (or such other Governmental Body, as the case may be) rate precedent. For the avoidance of doubt, “Qualifying Core Assets” shall also include necessary or ancillary expenses to support such assets (including working capital).
“Rate Base Amount” means an amount equal to the net utility plant of the Company Group, taken as a whole, as determined (without duplication) based on the most recently filed FERC Form 1s for each member of the Company Group that owns or operates FERC-jurisdictional assets.
“Remaining Annual Maximum Commitment Amount” means the Remaining ECL Annual Commitment Amount as of the date of determination plus the Remaining Growth Commitment Amount as of such date of determination.
“Remaining ECL Annual Commitment Amount” shall mean, as of the date of determination, (a) the lower of (i) the ECL Annual Commitment Amount for the applicable Commitment Year and (ii) an amount equal to the total cash distributions made to Investor Member (or, without duplication, its predecessors in interest or direct Transferees) pursuant to Section 5.2 in the prior eighteen (18) month period minus (b) the amount of capital contributions (but excluding any Excess Contributions that are distributed pursuant to Section 5.1(b)(i)) made by the Investor Member (or its predecessors in interest or direct Transferees) during such applicable Commitment Year pursuant to the ECLs (or any replacement Credit Support thereof). For the avoidance of doubt, in any given Commitment Year, all capital contributions (other than payment of the Contribution Agreement Purchase Price) made by Investor Member (or its predecessors in interest or direct Transferees) in such Commitment Year up to the ECL Annual Commitment Amount for such year shall be deemed to be amounts made pursuant to any or both ECLs (or any replacement Credit Support thereof), regardless of whether either ECL (or any replacement Credit Support thereof) was actually enforced or expressly called upon by the Company.
“Remaining Growth Commitment Amount” means, as of the date of determination, with respect to Investor Member (or its predecessors in interest), (a) the Growth Commitment Amount minus (b) the amount of all capital contributions (but excluding any Excess Contributions that are distributed pursuant to Section 5.1(b)(i)) made by Investor Member (or its predecessors in interest or direct Transferees) in respect of Additional Funding Requirements excluding the ECL Aggregate Funded Amounts; provided that, notwithstanding anything to the contrary, effective as of June 5, 2035, the Remaining Growth Commitment Amount shall be deemed to be zero dollars ($0).
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“Representatives” means the managers, directors, officers, employees, agents, members, partners and Advisors of a Party.
“Sanctioned Person” means any Person named from time to time on any Sanctions-related list of designated Persons maintained by an applicable Governmental Body described in the definition of “Sanctions,” including without limitation the list of sanctioned entities maintained by the United Nations; the Specially Designated Nationals and Blocked Persons List, the Foreign Sanctions Evaders List and the Sectoral Sanctions Identifications List, all administered by OFAC; the U.S. Denied Persons List, the U.S. Entity List, and the U.S. Unverified List, all administered by the U.S. Department of Commerce; the consolidated list of Persons, Groups and Entities Subject to E.U. Financial Sanctions, as implemented by the E.U. Common Foreign & Security Policy (collectively, the “Sanctioned Party Lists”); or (b) any Person owned or controlled by, or acting on behalf of, any Person named from time to time on any Sanctioned Party List.
“Sanctions” means any sanctions imposed, administered or enforced from time to time by OFAC, the U.S. Department of State, His Majesty’s Treasury, the United Nations, the European Union or any agency or subdivision of any of the foregoing, including any regulations, rules and executive orders issued in connection therewith.
“Subsidiary” means, with respect to any Person, any entity of which a majority of the total voting power of shares of stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof is at the time owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of such Person or a combination thereof or any partnership, association or other entity of which a majority of the partnership or other similar ownership interest is at the time owned or controlled, directly or indirectly, by such Person or one or more Subsidiaries of such Person or a combination thereof. For purposes of this definition, a Person is deemed to have a majority ownership interest in a partnership, limited liability company, association or other business entity if such Person is allocated a majority of the gains or losses of such partnership, limited liability company, association or other entity or is or controls the managing director or general partner of such partnership, limited liability company, association or other business entity.
“Tag Portion” means an amount of Membership Interests equal to the specified quantity of Tag-Along Offered Membership Interests multiplied by Investor Member’s Percentage Interest.
“Target CapEx” means, for the relevant period of determination, the aggregate dollar amount of capital expenditures incurred (on an accrual basis and without duplication) with respect to all Target Projects by any member of the Company Group or the AEP Outside Group, as applicable, and that are reasonably expected to be included in FERC-jurisdictional transmission rates.
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“Target CapEx Floor Percentage” means (a) for each four year period ending as of the end of each of calendar years 2025 through 2029, 70% and (b) for each four year period ending as of the end of each of calendar years 2030 through 2034, 65%.
“Target Project” means, excluding all Excluded Opportunities, any capital project, development, upgrade, expansion, modification or other capital expenditure for any transmission asset physically located within the Target States that is eligible to be developed or owned by a State Transco (as defined in the Project Selection Guidelines) and/or an AEP Operating Company (as defined in the Project Selection Guidelines) aligned with one or more of the Target States, in each case, pursuant to Section 4.1 of the Project Selection Guidelines (as interpreted in good faith, in a manner that is non-discriminatory to the Company Group and no less favorable in any material respect to the Company Group (i.e., it being less favorable for the Company Group to receive less Target CapEx) than the manner in which the AEP Member and its Affiliates have interpreted the Project Selection Guidelines and made allocation decisions in accordance therewith prior to the Effective Date).
“Target States” means the states of Ohio, Indiana and Michigan.
“Tax” or “Taxes” means any federal, state, local, foreign or other income, gross receipts, capital stock, capital gains, franchise, profits, withholding, payroll, social security, unemployment, disability, real property, ad valorem/personal property, stamp, excise, occupation, sales, use, excise, escheat, unclaimed property, transfer, value added, import, export, alternative minimum, estimated or other tax, duty, assessment or governmental charge of any kind whatsoever, including any interest, penalty or addition thereto.
“Tax Return” means any return, claim for refund, report, election, form, statement or information return relating to Taxes, including any schedule or attachment thereto, and including any amendments thereof.
“Third Party” means, with respect to a Member, another Person that is not another Member or an Affiliate of a Member.
“Transfer” shall mean, with respect to the legal or beneficial ownership of any of a Member’s Membership Interests, any sale, assignment, transfer, pledge, encumbrance, hypothecation or other similar arrangement or disposal, directly or indirectly, whether voluntarily, involuntarily or by operation of applicable Law including by the entry into any contract, option or other arrangement, or the granting or imposition of any Lien, that gives any Person other than the Member, whether or not upon the occurrence or nonoccurrence of an event, the right to acquire any Membership Interests or any interest therein, to vote any Membership Interest, or to require that any Membership Interests be transferred, directly or indirectly, whether voluntarily, involuntarily or by operation of applicable Law.
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For the avoidance of doubt and notwithstanding the foregoing, (a) subject to clauses (b), (c), (d) and (e) below, any sale, assignment, transfer, or other disposition of equity interests in any Member or any direct or indirect parent of such Member in which the Membership Interests held by such Member represent more than 50% of the Fair Market Value of all of the assets directly or indirectly held by such Member or direct or indirect parent the equity interests of which are being disposed shall constitute a “Transfer” for all purposes of this Agreement, (b) any direct or indirect transfer of equity interests in the Investor Member that does not result in a Change in Control of the Investor Member shall not constitute a “Transfer” for any purpose under this Agreement so long as (i) any required authorization, approval or consent of all applicable Governmental Bodies in respect of such transfer has been received, and (ii) such transfer would not reasonably be expected to result in the consequences specified in either clause (i) or clause (ii) of Section 6.3(c), (c) any direct or indirect transfer of equity interests in AEP Parent shall not constitute a “Transfer” for any purpose under this Agreement so long as any required authorization, approval or consent of all applicable Governmental Bodies in respect of such transfer has been received, (d) any direct or indirect transfer of equity interests in AEP Member (so long as the AEP Member is controlled by AEP Parent immediately prior to such transfer) shall not constitute a “Transfer” solely for purposes of Section 6.3 (i) unless (A) the Investor Member remains controlled by either of or any combination of (x) any Person or Persons advised, managed or controlled by KKR or its Affiliates and (y) any Person or Persons advised, managed or controlled by PSP or its Affiliates and (B) all or substantially all of the assets of the Person in which such interests are being transferred directly or indirectly consist of FERC regulated, transmission only electric utilities that are geographically aligned with AEP’s existing utility operating companies or otherwise constitute a “State Transco” in the Project Selection Guidelines and (ii) so long as any required authorization, approval or consent of all applicable Governmental Bodies or third parties in respect of such transfer has been received, (e) any direct or indirect transfer of equity interests in the AEP Member (so long as the AEP Member is controlled by AEP Parent immediately prior to such transfer) shall not constitute a “Transfer” solely for purposes of Section 6.4 unless all or substantially all of the assets of the Person in which such interests are being transferred directly or indirectly consist of equity securities of the Company Group and (ii) so long as any required authorization, approval or consent of all applicable Governmental Bodies or third parties in respect of such transfer has been received, (f) with respect to Investor Member, any bona fide direct or indirect Transfer of interests in any private equity fund or co-investment vehicle or similar investment vehicle (but, for the avoidance of doubt for purposes of this clause (f), excluding any portfolio company) that is an Affiliate of or is managed by KKR or its Affiliates or PSP or its Affiliates, as the case may be, or of any Person that holds a direct or indirect interest in such private equity fund, co-investment vehicle or similar investment vehicle, to another partner in such private equity fund, co-investment vehicle or similar investment vehicle or to a third party, so long as such private equity fund, co-investment vehicle or similar investment vehicle remains an Affiliate of or managed by KKR or its or its Affiliates or PSP or its Affiliates, as the case may be, in each case shall not constitute a “Transfer”, and (g) the issuance or transfer of any equity interests in any direct or indirect parent entity of Investor Member that is listed on a national securities exchange shall not constitute a “Transfer”.
“Transource” means Transource Energy, LLC, a Delaware limited liability company.
“Transource Agreement” means that certain Amended and Restated Operating Agreement of Transource Energy, LLC, dated as of January 21, 2019 (the “Transource Effective Date”), by and between AEP Transmission Holding Company, LLC and Evergy Transmission Company, LLC (f/k/a GPE Transmission Holding Company, LLC), without giving effect to any amendments following the Transource Effective Date to the extent such would adversely impact the Company Group.
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Section 13.17    Terms Defined Elsewhere in this Agreement. As used in this Agreement, the following terms shall have the meanings ascribed to them in the sections indicated:
Term Section
AAA Section 13.13(a)
Additional Funding Requirement Section 5.1(a)
AEP Managers Section 2.2(d)
AEP Member Preamble
Affiliate Transaction Default Section 2.14(c)
Affiliate Transactions Section 2.14(a)
Agreement Preamble
Board Section 2.1
Board Observer Section 2.13
Call Consummation Period Section 5.1(d)
Call Exercise Price Section 5.1(d)
Call Notice Section 5.1(d)
Call Period Section 5.1(d)
Call Right Section 5.1(d)
Capital Request Funding Date Section 5.1(a)
Capital Request Notice Section 5.1(a)
Company Preamble
Company Business Section 1.3(a)
Confidential Information Section 9.6(a)
Contributing Member Section 5.1(b)(ii)
Contribution Unfunded Amount Notice Section 5.1(b)
Corporate Opportunity Section 9.3(d)
Default Notice Section 2.14(c)
Defaulting Member Section 4.2
Designated Alternate Section 2.2(f)
Drag-Along Buyer Section 6.5(a)
Drag-Along Notice Section 6.5(b)
Drag-Along Right Section 6.5(a)
Drag-Along Sale Section 6.5(a)
Event of Default Section 4.1
Event of Dissolution Section 4.3(a)
Excess Contribution Section 5.1(b)(i)
Fund Indemnitees Section 11.7
Fund Indemnitors Section 11.7
Independent Evaluator Section 13.15
Investor Managers Section 2.2(b)
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Term Section
Investor Member Preamble
Investor Return Threshold Section 6.5(h)
Lock-Up Period Section 6.1(b)
Managers Section 2.1
MOIC Return Threshold Section 6.5(h)
Non-Contributing Member Section 5.1(b)
Non-Transferring Member Section 6.3(a)
Option Notice Section 6.6(a)
Over-Contributing Member Section 5.1(b)(i)
Party Preamble
Preemptive Right Section 7.1
Preemptive Right Notice Period Section 7.1
Preemptive Right Participation Notice Section 7.1
Pro Rata Request Amount Section 5.1(a)
Put Notice Section 6.6(a)
Put Sale Section 6.6(b)
Put Transaction Section 6.6(a)
Response To Capital Call Section 5.1(a)
Sale Notice Section 6.3(a)
Sale Period Section 6.3(a)(ii)
Sanctioned Party Lists Definition of “Sanctioned Person”
Subject Membership Interests Section 6.3(a)
Tax Allocation Agreement Section 8.1(i)
Tag-Along Buyer Section 6.4(a)
Tag-Along Election Notice Section 6.4(b)
Tag-Along Notice Section 6.4(a)
Tag-Along Offered Membership Interests Section 6.4(a)
Tag-Along Sale Section 6.4(a)
Tax-Driven Changes Section 10.7
Tax Matters Shareholder Section 10.2
Total Number of Managers Section 2.2(a)
Transferring Member Section 6.3(a)
Unfunded Amount Section 5.1(b)
Unfunded Amount Loan Section 5.1(b)(ii)(A)

Section 13.18    Other Definitional Provisions. The following shall apply to this Agreement:
(a)    Accounting terms which are not otherwise defined in this Agreement have the meanings given to them under GAAP. To the extent that the definition of an accounting term defined in this Agreement is inconsistent with the meaning of such term under GAAP, the definition set forth in this Agreement shall control.
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(b)    The terms “hereof,” “herein” and “hereunder” and terms of similar import are references to this Agreement as a whole and not to any particular provision of this Agreement. Section, clause, schedule and exhibit references contained in this Agreement are references to sections, clauses, schedules and exhibits in or to this Agreement, unless otherwise specified.
(c)    Whenever the words “include,” “includes” or “including” are used in this Agreement, they shall be deemed to be followed by the words “without limitation.” Where the context permits, the use of the term “or” shall be equivalent to the use of the term “and/or.”
(d)    When calculating the period of time before which, within which or following which any act is to be done or step taken pursuant to this Agreement, the date that is the reference date in calculating such period shall be excluded. If the last day of such period is a day other than a Business Day, the period in question shall end on the next succeeding Business Day. In addition, notwithstanding any deadline for payment, performance, notice or election under this Agreement, if such deadline falls on a date that is not a Business Day, then the deadline for such payment, performance, notice or election will be extended to the next succeeding Business Day.
(e)    Words denoting any gender shall include all genders, including the neutral gender. Where a word is defined herein, references to the singular shall include references to the plural and vice versa.
(f)    The word “will” will be construed to have the same meaning and effect as the word “shall”. The words “shall,” “will,” or “agree(s)” are mandatory, and “may” is permissive.
(g)    All references to “$” and dollars shall be deemed to refer to United States currency unless otherwise specifically provided.
(h)    All references to a day or days shall be deemed to refer to a calendar day or calendar days, as applicable, unless otherwise specifically provided.
(i)    Any reference to any Contract shall be a reference to such agreement or Contract, as amended, amended and restated, modified, supplemented or waived.
(j)    Any reference to any particular Code section or any Law shall be interpreted to include any amendment to, revision of or successor to that section or Law regardless of how it is numbered or classified; provided, that, for the purposes of the representations and warranties contained herein, with respect to any violation of or non-compliance with, or alleged violation of or non-compliance, with any Code section or Law, the reference to such Code section or Law means such Code section or Law as in effect at the time of such violation or non-compliance or alleged violation or non-compliance.
(k)    For all purposes of this Agreement (including the determination of a Member’s Percentage Interest and its entitlement, if applicable, to designate one or more
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Managers), such Member and its Affiliates shall be deemed to be, and shall be treated as, one and the same Member.
[Remainder of Page Intentionally Left Blank]

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IN WITNESS WHEREOF, the undersigned has duly executed this Agreement as of the date first written above.
The Company:
Midwest Transmission Holdings, LLC

By: /s/ Robert W. Bradish            
Name: Robert W. Bradish
Title: Vice President


[Signature Page to Amended and Restated Limited Liability Company Agreement]

IN WITNESS WHEREOF, the undersigned has duly executed this Agreement as of the date first written above.
AEP Member:
AEP Transmission Company, LLC

By: /s/ Robert W. Bradish            
Name: Robert W. Bradish
Title: Vice President

[Signature Page to Amended and Restated Limited Liability Company Agreement]

IN WITNESS WHEREOF, the undersigned has duly executed this Agreement as of the date first written above.
Investor Member:
Olympus BidCo L.P.
By: Olympus GPCo, LLC, its general partner

By: /s/ Kathleen Lawler            
Name: Kathleen Lawler
Title: Co-President

By: /s/ Louis-Eric Bonin                
Name: Louis-Eric Bonin
Title: Co-President


                        
[Signature Page to Amended and Restated Limited Liability Company Agreement]

Schedule 1
Schedule of Members
Name Address Percentage Interest
AEP Transmission Company, LLC
AEP Transmission Company, LLC
c/o American Electric Power Service Corporation
1 Riverside Plaza
Columbus, OH 43215
Attention: Robert W. Bradish
Email: rwbradish@aep.com
 80.1%
Olympus BidCo L.P.
Olympus BidCo L.P.
30 Hudson Yards, Suite 7500
New York, New York 10001
Attention: Kathleen Lawler and Louis-Éric Bonin
Email: Kathleen.Lawler@kkr.com; and LEBonin@investpsp.ca
 19.9%



Schedule 2
Prohibited Competitors
1.    AES Corp.
2.    American Municipal Power
3.    CenterPoint Energy
4.    Dominion Energy
5.    Duke Energy
6.    Duquesne Light Company
7.    Exelon
8.    FirstEnergy
9.    Invenergy
10.    ITC Holdings
11.    LS Power
12.    NextEra Energy
13.    NiSource
14.    Pattern Energy
15.    Public Service Enterprise Group
16.    PPL Corp.
17.    Viridon
EX-31.A 3 ex31aaep20252q.htm EX-31.A Document

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, William J. Fehrman, certify that:
1.I have reviewed this report on Form 10-Q of American Electric Power Company, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer

EX-31.A 4 ex31aaeptco20252q.htm EX-31.A Document

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, William J. Fehrman, certify that:
1.I have reviewed this report on Form 10-Q of AEP Transmission Company, LLC;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 30, 2025 By: /s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer

EX-31.A 5 ex31aaeptexas20252q.htm EX-31.A Document

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, William J. Fehrman, certify that:
1.I have reviewed this report on Form 10-Q of AEP Texas Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer

EX-31.A 6 ex31aapco20252q.htm EX-31.A Document

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, William J. Fehrman, certify that:
1.I have reviewed this report on Form 10-Q of Appalachian Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer

EX-31.A 7 ex31aim20252q.htm EX-31.A Document

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, William J. Fehrman, certify that:
1.I have reviewed this report on Form 10-Q of Indiana Michigan Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer

EX-31.A 8 ex31aopco20252q.htm EX-31.A Document

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, William J. Fehrman, certify that:
1.I have reviewed this report on Form 10-Q of Ohio Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer

EX-31.A 9 ex31apso20252q.htm EX-31.A Document

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, William J. Fehrman, certify that:
1.I have reviewed this report on Form 10-Q of Public Service Company of Oklahoma;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer

EX-31.A 10 ex31aswepco20252q.htm EX-31.A Document

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, William J. Fehrman, certify that:
1.I have reviewed this report on Form 10-Q of Southwestern Electric Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer

EX-31.B 11 ex31baep20252q.htm EX-31.B Document

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Trevor I. Mihalik, certify that:

1.I have reviewed this report on Form 10-Q of American Electric Power Company, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer

EX-31.B 12 ex31baeptco20252q.htm EX-31.B Document

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Trevor I. Mihalik, certify that:

1.I have reviewed this report on Form 10-Q of AEP Transmission Company, LLC;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer

EX-31.B 13 ex31baeptexas20252q.htm EX-31.B Document

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Trevor I. Mihalik, certify that:

1.I have reviewed this report on Form 10-Q of AEP Texas Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer

EX-31.B 14 ex31bapco20252q.htm EX-31.B Document

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Trevor I. Mihalik, certify that:

1.I have reviewed this report on Form 10-Q of Appalachian Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer

EX-31.B 15 ex31bim20252q.htm EX-31.B Document

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Trevor I. Mihalik, certify that:

1.I have reviewed this report on Form 10-Q of Indiana Michigan Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer

EX-31.B 16 ex31bopco20252q.htm EX-31.B Document

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Trevor I. Mihalik, certify that:

1.I have reviewed this report on Form 10-Q of Ohio Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer

EX-31.B 17 ex31bpso20252q.htm EX-31.B Document

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Trevor I. Mihalik, certify that:

1.I have reviewed this report on Form 10-Q of Public Service Company of Oklahoma;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer

EX-31.B 18 ex31bswepco20252q.htm EX-31.B Document

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Trevor I. Mihalik, certify that:

1.I have reviewed this report on Form 10-Q of Southwestern Electric Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2025 By: /s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer

EX-32.A 19 ex32aaep20252q.htm EX-32.A Document

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, William J. Fehrman, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.A 20 ex32aaeptco20252q.htm EX-32.A Document

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of AEP Transmission Company, LLC (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, William J. Fehrman, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to AEP Transmission Company, LLC and will be retained by AEP Transmission Company, LLC and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.A 21 ex32aaeptexas20252q.htm EX-32.A Document

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of AEP Texas Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, William J. Fehrman, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to AEP Texas Inc. and will be retained by AEP Texas Inc. and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.A 22 ex32aapco20252q.htm EX-32.A Document

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, William J. Fehrman, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company and will be retained by Appalachian Power Company and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.A 23 ex32aim20252q.htm EX-32.A Document

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, William J. Fehrman, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company and will be retained by Indiana Michigan Power Company and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.A 24 ex32aopco20252q.htm EX-32.A Document

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, William J. Fehrman, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to Ohio Power Company and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.A 25 ex32apso20252q.htm EX-32.A Document

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, William J. Fehrman, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma and will be retained by Public Service Company of Oklahoma and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.A 26 ex32aswepco20252q.htm EX-32.A Document

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, William J. Fehrman, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ William J. Fehrman
William J. Fehrman
Chief Executive Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.B 27 ex32baep20252q.htm EX-32.B Document

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, Trevor I. Mihalik, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.B 28 ex32baeptco20252q.htm EX-32.B Document

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of AEP Transmission Company, LLC (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, Trevor I. Mihalik, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to AEP Transmission Company, LLC and will be retained by AEP Transmission Company, LLC and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.B 29 ex32baeptexas20252q.htm EX-32.B Document

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of AEP Texas Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, Trevor I. Mihalik, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to AEP Texas Inc. and will be retained by AEP Texas Inc. and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.B 30 ex32bapco20252q.htm EX-32.B Document

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, Trevor I. Mihalik, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company and will be retained by Appalachian Power Company and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.B 31 ex32bim20252q.htm EX-32.B Document

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, Trevor I. Mihalik, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company and will be retained by Indiana Michigan Power Company and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.B 32 ex32bopco20252q.htm EX-32.B Document

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, Trevor I. Mihalik, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to Ohio Power Company and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.B 33 ex32bpso20252q.htm EX-32.B Document

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, Trevor I. Mihalik, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma and will be retained by Public Service Company of Oklahoma and furnished to the Securities and Exchange Commission or its staff upon request.
EX-32.B 34 ex32bswepco20252q.htm EX-32.B Document

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2025 as filed with the Securities and Exchange Commission on the date hereof, I, Trevor I. Mihalik, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Trevor I. Mihalik
Trevor I. Mihalik
Chief Financial Officer


July 30, 2025

A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.