AMERICAN ELECTRIC POWER CO INC

EXECUTIVE OVERVIEW

AEP CONSOLIDATED RESULTS OF OPERATIONS

Earnings Attributable to AEP Common Shareholders decreased from $1.0 billion in 2024 to $800 million in 2025 primarily due to:

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

This decrease was partially offset by:

•Favorable rate proceedings in AEP’s various jurisdictions.

•An increase in sales volumes driven by favorable weather.

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

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.

(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 recently approved legislation in Ohio.

(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 remeasurement of excess ADIT in Arkansas.

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

(e)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.

RECENT DEVELOPMENTS AND TRANSACTIONS

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 March 31, 2025, AEP expects approximately $2.3 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.

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

In January 2025, AEP announced a partnership between nonaffiliated entities to acquire a 19.9% noncontrolling interest in OHTCo and IMTCo for $2.82 billion. 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. The transaction has received clearance from the Committee on Foreign Investment in the United States and remains subject to FERC approval. AEP expects to close on the transaction in the second half of 2025. If the transaction does not close, it could reduce expected future cash flows and impact financial condition.

Valley Link Investment (Applies to AEP and Transource Energy)

In July 2024, Transource Energy, VEPCO and FirstEnergy entered into a joint proposal agreement in connection with PJM’s 2024 Regional Transmission Expansion Plan process on transmission system upgrades to improve reliability and increase power availability in states including Indiana, Maryland, Ohio, Virginia and West Virginia. Pursuant to such joint proposal agreement, Transource Energy, VEPCO and FirstEnergy Transmission, LLC, a subsidiary of FirstEnergy, jointly proposed certain regional electric transmission projects for PJM's consideration. In November 2024, Transource Energy, Dominion High Voltage MidAtlantic, Inc., an affiliate of VEPCO, and FirstEnergy Transmission, LLC formed Valley Link, which is the holding company responsible for managing and executing any projects awarded by PJM, and entered into a limited liability agreement. In February 2025, those jointly proposed regional electric transmission projects, which were selected by PJM board to address forecasted conditions that would create reliability concerns, include approximately $3 billion in investments for Valley Link to both build new and upgraded existing transmission infrastructure. Transource Energy’s investment is estimated to be $1.1 billion.

In March 2025, 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 requests approval of certain Federal Power Act Section 219 transmission incentive rate treatments in connection with each Company’s respective investment in the Valley Link Project Portfolio.

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 utility 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 March 31, 2025, OPCo has signed two contracts for electricity service from fuel cells. In February 2025, OPCo requested PUCO approval of those two contracts. Approved legislation in Ohio, if enacted to law, repeals the underlying statutory authority prospectively. See “Ohio Legislation” section below for additional information.

NOLCs in Retail Jurisdictions - IRS PLRs

The Registrants have made rate filings with state commissions to transition to stand-alone treatment of NOLCs in retail rate making. The Registrants completed the transition in Michigan, Tennessee, West Virginia and Virginia prior to 2025. In the most recent KPCo, I&M (Indiana jurisdiction), PSO and SWEPCo base rate cases, the companies filed to transition to stand-alone rate making which was contingent upon a supportive PLR from the IRS.

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 rate making 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:

(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.

Beginning in the second quarter of 2024 and continuing until the NOLC revenue requirement is in rates, AEP is recognizing additional regulatory assets related to revenue requirement amounts to be collected from customers. As of March 31, 2025, AEP has NOLC regulatory assets of $102 million on its balance sheet.

In the second quarter of 2024, requests seeking to establish a recovery mechanism for these regulatory assets were filed in Indiana, Oklahoma and Texas. Certain intervenors in each jurisdiction have challenged the recovery or have proposed ratemaking treatment that would offset the recovery of the regulatory assets.

In March 2025, the IURC issued an order approving I&M’s request to collect the regulatory asset over 2 years and collect the ongoing revenue requirement associated with the stand-alone NOLC. In February 2025, an ALJ in Oklahoma issued a report recommending PSO be allowed to collect the regulatory asset over 20 months and collect the ongoing revenue requirement associated with the stand-alone treatment of NOLCs, as well as record a regulatory liability for all NOLC collections. A final order from the OCC is expected in the second quarter of 2025. SWEPCo and certain intervenors filed a settlement agreement with the PUCT in March 2025. If the settlement is approved by the PUCT, it would allow SWEPCo to begin recovery of the regulatory asset, subject to refund. The recovery mechanism would collect the regulatory asset over 3 years and collect the ongoing annual revenue requirement. Parties reserved the right to challenge the treatment of NOLC on a stand-alone ratemaking basis in a future proceeding.

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:

(a)Percentage change for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024.

(b)The increase in commercial sales was primarily due to new data processor loads and economic development.

Inflation, Tariffs on International Trade and Supply Chain Disruption

The United States economy has been in an elevated inflationary environment. 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 and tariffs on internation 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

In July 2024, I&M submitted an application to the IURC to modify its Industrial Power Tariff to incorporate terms and conditions of service that would apply to large load customers with a load, individually or in the aggregate, greater than 150 MW. Among other things, the proposal aimed to extend the duration of ESAs, implement higher minimum demand charges compared to current tariff provisions and address changes in contract capacity commitments and termination of service.

In November 2024, I&M, the Indiana Office of Utility Consumer Counselor and all intervening parties submitted a unanimous joint settlement agreement resolving all issues. The settlement agreement included terms that lowered the threshold for individual customer loads to 70 MW, reduced the minimum contract term to 12 years plus the load ramp period not to exceed 5 years, revised how a customer’s minimum bill would be calculated and revised terms and conditions associated with contract capacity commitments and termination of service.

In February 2025, the IURC issued an order approving the terms of the joint settlement, with one modification. The modification to the settlement agreement in the approved order, which has been accepted by all settling parties, states that any reduction of more than 20% of a large load customer’s contract capacity, that is mutually agreed upon between I&M and the large load customer, must be submitted to the IURC for its review and approval before becoming effective. This modification allows for increased transparency and IURC oversight of any significant changes to a large load customer’s commitment and any associated impacts of such changes.

In May 2024, OPCo submitted an application to the PUCO to establish new tariffs for data centers and mobile data centers that enter new retail service contracts after the tariff's effective date. Among other things, the proposal aimed to extend the duration of ESAs and implement higher minimum demand charges compared to current tariffs. In October 2024, intervening parties representing data centers and certain other parties presented a stipulation endorsing the application with certain adjustments, including broadening the tariff's applicability to all large loads (not limited to data centers) that meet specified criteria, as well as reducing the proposed minimum demand charges.

Subsequently, in October 2024, OPCo, along with the PUCO Staff, the Ohio Consumers Counsel, and additional parties, filed a separate stipulation proposing the approval of the application with modifications. This stipulation recommended retaining the application’s proposal to apply the tariff only to data center customers and it proposed setting minimum demand charges that were higher than those proposed in the October 2024 stipulation but lower than those in the original application. Hearings were held in December 2024 and January 2025 and briefing was completed in early April 2025. OPCo anticipates a PUCO decision in 2025.

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 2,303 MWs of owned renewable generation facilities, totaling approximately $5.5 billion. The estimated cost of these facilities is included in the Budgeted Capital Expenditures disclosure included in the Financial Condition section below. In addition, AEP has received regulatory approvals for 637 MWs of renewable PPAs. The following table summarizes regulatory approvals received for active renewable projects as of March 31, 2025:

(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 three wind facilities and one solar facility for a combined total capacity of 742 MWs. These facilities are part of the approved projects contemplated within PSO’s 892 MWs of total new renewable generation.

Natural Gas Generation

In June 2024, PSO entered into a PSA to acquire a 795 MW combined-cycle power generation facility located in Oklahoma. The acquisition is subject to OCC pre-approval including the approval of a rider to allow asset recovery prior to the inclusion in base rates in a future rate case. In January 2025, intervenors and the OCC staff filed testimony. While the OCC staff testified that PSO established the need for the acquisition and the Oklahoma Attorney General agreed that PSO considered reasonable alternatives, other intervenors requested additional analysis on the requirement to consider reasonable alternatives and recommended future cost caps and performance guarantees. PSO filed rebuttal testimony in January 2025 and a hearing with the OCC took place in March 2025. The acquisition has received approval from the FERC. In April 2025, an ALJ recommended the OCC deny pre-approval. In May 2025, PSO filed written exceptions to the ALJ recommendation to clarify the record for the benefit of the OCC. The OCC is open to reject or modify the ALJ’s recommendation based on all evidence presented. Subject to obtaining the required approval from the OCC, PSO expects to close on the transaction by June 30, 2025.

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.

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

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

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

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 March 31, 2025, by year, for the five year period 2025-2029:

(a)In April 2025, SWEPCo entered into a 150 MW capacity purchase agreement for delivery start years of 2028, 2029 and 2030.

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.

Other Significant Regulatory Matters

FERC 2021 PJM and SPP Transmission Formula Rate Challenge

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:

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.

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 request 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 their initial orders.

As a result of the January 2024 FERC orders, the Registrants’ balance sheets have reflected a liability for the probable refund of all NOLC revenues included in transmission formula rates for years 2021 through 2025, with interest. The Registrants have not yet been directed to make cash refunds related to 2022 through 2025 rate years. The probable refunds to affiliated and nonaffiliated customers are reflected as Deferred Credits and Other Noncurrent Liabilities on the balance sheets, with the exception of remaining amounts expected to be refunded within one year which are reflected in Other Current Liabilities. Refunds probable to be received by affiliated companies, resulting in a reduction to affiliated transmission expense, were deferred as an increase to Regulatory Liabilities or a reduction to Regulatory Assets on the balance sheets where management expects that refunds would be returned to retail customers through authorized retail jurisdiction rider mechanisms.

Kentucky Securitization Case

In January 2024, the KPSC issued a financing order approving KPCo’s request to securitize certain regulatory assets balances as of the time securitization bonds are issued and concluding that costs requested for recovery through securitization were prudently incurred. The KPSC’s financing order includes certain additional requirements related to securitization bond structuring, marketing, placement and issuance that were not reflected in KPCo’s proposal. In accordance with Kentucky statutory requirements and the financing order, the issuance of the securitized bonds is subject to final review by the KPSC after bond pricing. KPCo expects to proceed with the securitized bond issuance process and to complete the securitization process in 2025, subject to market conditions. As of March 31, 2025, regulatory asset balances expected to be recovered through securitization total $495 million and include: (a) $307 million of plant retirement costs, (b) $79 million of deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, (c) $50 million of deferred purchased power expenses, (d) $56 million of under-recovered purchased power rider costs and (e) $3 million of deferred issuance-related expenses, including KPSC advisor expenses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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 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 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.

The WVPSC issued a procedural schedule for the Companies’ securitization filing with testimony due in May 2025 and a hearing scheduled for July 2025.

Virginia Legislation Enacted in 2025 – Impacting Future Rate Cases and Securitization

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 31 st to May 31 st, with a final Virginia SCC order to be issued on these future filings no later than January 15 th of the subsequent year and resulting updated base rates implemented no earlier than March 1 st. 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, to request 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. APCo intends to submit a securitization filing with the Virginia SCC in July 2025.

Ohio Legislation

In July 2019, Ohio House Bill 6 (HB 6), which offered incentives for power-generating facilities with zero or reduced carbon emissions, was signed into law by the Ohio Governor. HB 6 terminated energy efficiency programs as of December 31, 2020, including OPCo’s shared savings revenues of $26 million annually and phased out renewable mandates after 2026. HB 6 also provided for continued recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for continued recovery of OVEC costs through 2030 which is allocated to all electric distribution utility customers in Ohio on a non-bypassable basis. OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040.

In March 2021, the Governor of Ohio signed legislation that, among other things, repealed the payments to the nonaffiliated owner of Ohio’s nuclear power plants that were previously authorized under HB 6. The new legislation, House Bill 128, went into effect in May 2021 and leaves unchanged other provisions of HB 6 regarding energy efficiency programs, recovery of renewable energy costs and recovery of OVEC costs.

In April 2025, Ohio House Bill 15 (HB 15) was approved by the Ohio legislature, which if enacted to law, would: (a) alter 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) eliminate 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) repeal 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. HB 15 is subject to review by the Governor of Ohio.

As a result of the legislature’s approval of HB 15, 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.

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. Management is unable to 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 new Presidential administration.

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

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

Impact of Environmental Compliance on the Generating Fleet

The rules and environmental control requirements discussed below will have a material impact on AEP’s operations. As of March 31, 2025, AEP owned generating capacity of approximately 23,200 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.

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 PM 2.5 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 SO 2 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. The proposed rule was published in the Federal Register in October 2024, initiating a public comment period ending November 14, 2024. The deadline for the Federal EPA to take final action on the Texas SIP is May 30, 2025.

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 PM 2.5 NAAQS in downwind states. CSAPR relies on SO 2 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, CO 2 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 CO 2 emissions from coal fired plants and carbon capture and sequestration or limited utilization to reduce CO 2 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.

AEP is in the early stages of evaluating and identifying the best strategy for complying with this and other new rules, discussed below, while ensuring the adequacy of resources to meet customer needs. 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. The Federal EPA has since announced plans to reconsider the rule. 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. Management cannot predict the outcome of that litigation or any future actions by the Federal EPA related to the rule. Excessive costs to comply with environmental regulations have led to the announcement of early plant closures across the country. The Federal EPA’s new GHG rules, and suite of other new rules issued simultaneously which are 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 new administration evaluates the rule, and while the Federal EPA has not formally proposed any actions, in March 2025, the Administrator of the Federal EPA indicated that the agency would be reconsidering the MATS 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. Management is evaluating the impacts of the rule, but does not anticipate any significant challenges complying with the rule.

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. 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 March 31, 2025, of generating facilities retired or planned for early retirement in advance of the retirement date currently authorized for ratemaking purposes:

(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.

(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.

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 March 31, 2025 as compared to the three months ended March 31, 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 months ended March 31, 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 tables present Earnings (Loss) Attributable to AEP Common Shareholders by segment:

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.

VERTICALLY INTEGRATED UTILITIES

Summary of KWh Energy Sales for Vertically Integrated Utilities

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities

•Retail Revenues increased $195 million primarily due to the following:

•An $83 million increase in weather-related usage primarily in the residential class driven by a 31% increase in heating degree days.

•An $82 million increase in rider revenues across all companies.

•A $39 million increase in base rate revenues at I&M and PSO.

•A $33 million increase in fuel revenues primarily due to increases at APCo and I&M, partially offset by a decrease at PSO.

•A $49 million decrease due to regulatory provisions for refund at I&M.

•A $12 million decrease in weather-normalized revenues primarily in the industrial class.

•Off-system Sales increased $6 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales at I&M.

•Transmission Revenues increased $8 million primarily due to continued investment in transmission assets.

•Other Revenues decreased $20 million primarily due to a decrease in sales of renewable energy credits at APCo and decreased revenues from a customer project to enhance transmission resilience at PSO.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation increased $76 million primarily due to increases at APCo, I&M and SWEPCo, partially offset by a decrease at PSO.

•Depreciation and Amortization expenses increased $62 million primarily due to the following:

•A higher depreciable base at APCo, I&M and SWEPCo.

•A prior year deferral of Excess ADIT as a result of the PLR received regarding the treatment of stand-alone NOLCs.

•Amortization of Storm Recovery Funding securitized assets and other regulatory assets at SWEPCo.

•Taxes Other Than Income Taxes decreased $6 million primarily due to lower franchise taxes and business and occupation taxes at APCo.

•Non-Service Cost Components of Net Periodic Pension Cost increased $8 million primarily due to an increase in loss amortization and discount rates from 2024 to 2025.

•Interest Expense increased $44 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 rate making.

•Income Tax Expense increased $251 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 recorded in 2024.

•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.

TRANSMISSION AND DISTRIBUTION UTILITIES

Summary of KWh Energy Sales for Transmission and Distribution Utilities

(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

•Retail Revenues increased $26 million primarily due to the following:

•A $78 million increase in rider revenues.

•A $43 million increase in weather-related usage driven by a 30% increase in heating degree days in the eastern region and an 81% increase in heating degree days and a 10% increase in cooling degree days in the western region.

•A $14 million increase in revenue from the base rate case in Texas.

•A $76 million decrease due to lower prices and lower customer participation in OPCo’s SSO.

•A $28 million decrease in weather-normalized revenues in all classes in Ohio.

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

•Transmission Revenues increased $21 million primarily due to an increase in interim rates driven by increased transmission investments in Texas.

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

•Purchased Electricity for Resale expenses decreased $12 million primarily due to $45 million in decreased recoverable purchases to serve SSO customers partially offset by a $35 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.

•Purchased Electricity from AEP Affiliates expenses decreased $31 million primarily due to decreased recoverable purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $58 million primarily due to the following:

•A $70 million increase in recoverable transmission expenses.

This increase was partially offset by:

•An $11 million decrease in distribution expenses in Ohio primarily related to recoverable storm restoration costs and recoverable vegetation management expenses.

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

•Depreciation and Amortization expenses decreased $20 million primarily due tothe 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.

•A $10 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 increased$14 million primarily due to higher property taxes driven by additional investments in transmission and distribution assets.

•Interest Expense increased $15 million primarily due to higher debt balances and interest rates in Texas.

AEP TRANSMISSION HOLDCO

Summary of Investment in Transmission Assets for AEP Transmission Holdco

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

•Transmission Revenues increased $45 million primarily due to continued investment in transmission assets.

•Depreciation and Amortization expenses increased $8 million due to a higher depreciable base.

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

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

•An $8 million increase due to an increase in pretax book income.

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

GENERATION & MARKETING

•Merchant Generation increased $23 million primarily due to higher realized prices in 2025.

•Renewable Generation decreased $7 million primarily due to the sale of Onsite Partners in September 2024.

•Retail, Trading and Marketing increased $167 million primarily due to higher MTM hedging activity and higher market prices in 2025.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $210 million primarily due to an increase in energy costs in 2025.

•Interest and Investment Income decreased $5 million primarily due to the sale of Onsite Partners in September 2024.

•Income Tax Expense increased $11 million primarily due to the amortization of deferred ITCs from the sale of NMRD in 2024.

CORPORATE AND OTHER

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $54 million in 2024 to a loss of $26 million in 2025 primarily due to:

•A $13 million decrease in corporate expenses.

•A $13 million increase in equity earnings.

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

•A $10 million increase in Income Tax Benefit primarily due to an increase in PTCs.

•A $9 million decrease in interest expense due to lower interest rates.

These increases in earnings were partially offset by:

•A $17 million decrease at EIS primarily due to an increase in insurance reserves.

•An $11 million decrease in interest income primarily due to lower advances to affiliates.

AEP CONSOLIDATED INCOME TAXES

Income Tax Expense increased $267 million primarily due to:

•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 $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.

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

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

AEP’s ratio of debt-to-total capital increased from 62.6% to 62.8% as of December 31, 2024 and March 31, 2025, respectively, primarily due to an increase in debt to support distribution and transmission investment 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 March 31, 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 three months ended March 31, 2025.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of March 31, 2025, available liquidity was approximately $3.8 billion as illustrated in the table below:

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers. The maximum amount of commercial paper outstanding during the first three months of 2025 was $2.4 billion. The weighted-average interest rate for AEP’s commercial paper for the three months ended March 31, 2025 was 4.63%.

Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 2025 was $252 million with maturities ranging from April 2025 to March 2026. In April 2025, AEP issued an additional $52 million of letters of credit under existing uncommitted facilities with maturity dates ranging from October 2025 to April 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 March 31, 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 March 31, 2025, this contractually-defined percentage was 59%. 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 12 for additional information regarding AEP’s forward sale of 22,549,020 shares of common stock in March 2025.

ATM Program

AEP participates in an ATM program that allows AEP to issue, from time to time, shares of its common stock, including shares of common stock that may be sold pursuant to an equity forward sales agreement. As of March 31, 2025, approximately $1.3 billion of equity is available for issuance under the ATM program. See Note 12 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors of AEP (AEP Board) declared a quarterly dividend of $0.93 per share in April 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 12 for additional information.

Credit Ratings

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

CASH FLOW

AEP relies primarily on cash flows from operations, debt issuances, issuances of common stock under the ATM program 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.

Operating Activities

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes and AFUDC.

Net Cash Flows from Operating Activities increased by $8 million primarily due to the following:

•A $108 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

•An $80 million increase in cash from changes in Other Noncurrent Liabilities. This increase is primarily due to changes in provisions for refunds and regulatory liabilities driven by timing differences in refunds to customers under rate rider mechanisms.

These increases in cash were partially offset by:

•A $118 million decrease in cash primarily due to the timing of fuel and purchase power related revenues and expenses.

•A $56 million decrease in cash due to changes in risk management contract collateral positions.

Investing Activities

Net Cash Flows Used for Investing Activities increased by $433 million primarily due to the following:

•A $339 million increase in Construction Expenditures primarily due to increases in Transmission and Distribution Utilities of $132 million, Vertically Integrated Utilities of $119 million and AEP Transmission Holdco of $61 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

Net Cash Flows from Financing Activities increased by $568 million primarily due to the following:

•A $933 million decrease in retirements of long-term debt. See Note 12 - Financing Activities for additional information.

This increase in cash was partially offset by:

•A $298 million decrease in issuances of long-term debt. See Note 12 - Financing Activities for additional information.

•An $85 million decrease due to changes in short-term debt. See Note 12 - Financing Activities for additional information.

See the “Long-term Debt Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after March 31, 2025 through May 6, 2025, the date that the first quarter Form 10-Q was filed.

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.

The expenditures are generally for transmission, generation, distribution, regulated renewables and required environmental investment to comply with the Federal EPA rules. 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 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 “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.