AMERICAN ELECTRIC POWER CO INC (AEP) FY 2024 MD&A

RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

AEP is one of the largest investor-owned electric public utility holding companies in the United States.  AEP’s electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

AEP’s subsidiaries operate an extensive portfolio of assets including:

•Approximately 225,000 circuit miles of distribution lines that deliver electricity to 5.6 million customers.

•Approximately 40,000 circuit miles of transmission lines, including approximately 2,100 circuit miles of 765 kV lines, the backbone of the electric interconnection grid in the eastern United States.

•Approximately 23,000 MWs of regulated owned generating capacity as of December 31, 2024, one of the largest complements of generation in the United States.

AEP is committed to executing its strategy to provide customers with reliable, affordable power. AEP’s vision is focused on six core principles:

•Delivering industry leading customer service.

•Providing a safe and secure workplace for our engaged, trained and developed employees.

•Environmental respect through creative sustainable energy solutions.

•Regulatory and legislative integrity that achieves balanced regulatory outcomes and provides trusted industry leadership.

•Operational excellence.

•Strong financial discipline that drives value for customers and investors.

AEP is at the forefront of the energy industry’s transformation. AEP’s core strategy is focused on three pillars: 1) reinvestment in core assets, 2) investment in growth opportunities and 3) acquisition of new assets. Highlights of AEP’s strategy include:

•The announcement of a five-year, $54 billion capital investment plan that continues to build the energy grid of the future.

•Adding more than 20,000 MWs of diverse generation resources through 2034 to support resource adequacy, resiliency, affordability and the increasing customer demand for power driven by data processors and economic development.

•Building a culture of accountability and operational excellence to effectively support regulated operations and enhance customer service.

•Maintaining a strong balance sheet and achieving our financial targets.

AEP CONSOLIDATED RESULTS OF OPERATIONS

2024 Compared to 2023

Earnings Attributable to AEP Common Shareholders increased from $2.2 billion in 2023 to $3.0 billion in 2024 primarily due to:

•A 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.

•Favorable rate proceedings in AEP’s various jurisdictions.

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

•An increase in sales volumes driven by favorable weather.

•Unfavorable regulatory decisions in Texas, West Virginia and at FERC in 2023.

•A loss on the sale of the competitive contracted renewables portfolio in 2023.

These increases were partially offset by:

•A revenue refund provision related to SWEPCo’s 2012 Texas Base Rate Case and the Turk Plant.

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

•An increase in severance expenses and pension settlement expenses resulting from the voluntary severance program announced in April 2024.

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

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RECENT DEVELOPMENTS AND TRANSACTIONS

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% indirect 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 is subject to FERC approval and clearance from the Committee on Foreign Investment in the United States. 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.

Acquisition of the Diversion Wind Farm

In December 2024, SWEPCo acquired 100% of the equity interests in Diversion Wind Energy, LLC, the owner of Diversion wind farm. The Diversion wind farm is a newly constructed 201 MW wind facility located in Baylor County, Texas and was placed in service in December 2024. Output from Diversion serves FERC wholesale load and retail customers in Arkansas and Louisiana. SWEPCo’s Louisiana jurisdictional share of the Diversion revenue requirement, net of PTC benefit, is recoverable through an authorized rider until the amounts are reflected in base rates. Recovery of the Arkansas portion of the Diversion revenue requirement is expected to begin in 2026 through base rates. See the “Diversion Wind Farm” section of Note 7 for additional information.

Disposition of AEP Onsite Partners

In May 2024, AEP signed an agreement to sell AEP OnSite Partners to a nonaffiliated third-party. AEP OnSite Partners targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions. In September 2024, AEP completed the sale to a nonaffiliated third-party and received cash proceeds of approximately $318 million, net of taxes and transaction costs. The proceeds were used to pay down short-term debt. See the “Disposition of AEP OnSite Partners” section of Note 7 for additional information.

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. Through the date of this filing OPCo has signed multiple contracts for electricity service from fuel cells with customers and is filing those contracts with the PUCO for approval. See “AEP Development Services (Applies to OPCo)” section of Note 18 for additional information.

CCR Rule Revisions

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 as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land. 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. See “CCR Rule” section in Environmental Issues 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 Tennessee, West Virginia and Virginia prior to 2024 and in Michigan in July 2024. 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:

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(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. Through December 31, 2024, AEP has recognized NOLC regulatory assets of $93 million.

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 the fourth quarter of 2024, hearings on the merits were held in Indiana and Oklahoma. In January 2025, a second hearing on the merits in Oklahoma was held. A hearing is scheduled for the first quarter of 2025 in Texas.

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 $122 million pretax expense in the second quarter of 2024 related to this voluntary severance program. The Registrants paid $118 million of the severance benefits in the second half of 2024. In addition, AEP also recognized a settlement charge of $90 million in 2024 due to the remeasurement of pension obligations driven by the voluntary severance program. AEP will seek recovery for the portion of the expense related to regulated operations. See Note 14 - Voluntary Severance Program for additional information.

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Customer Demand

AEP uses sales volumes by customer class as a way to measure drivers of customer demand. In 2024, AEP experienced an increase in customer demand for power driven by the growth in new data processing loads and economic development in the commercial customer class. AEP currently forecasts continued growth in customer demand in 2025. The percentage change and forecasted percentage change in sales volumes by customer class are shown in the table below.

(a)Percentage change for the year ended December 31, 2024 as compared to the year ended December 31, 2023.

(b)Forecasted percentage change for the year ending December 31, 2025 compared to the year ended December 31, 2024.

(c)The commercial sales growth is primarily due to new data processor loads and economic development.

Large Load and 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 electric service agreements (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. A hearing was held and the parties submitted a joint proposed order in December 2024. I&M anticipates an IURC decision in 2025.

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 suggesting 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. OPCo anticipates a PUCO decision in 2025.

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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 are 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 December 31, 2024:

(a)APCo 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 893 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 PSO considered reasonable alternatives, other recommendations included requesting additional analysis on the requirement to consider reasonable alternatives and recommending future cost caps and performance guarantees. PSO filed rebuttal testimony in January 2025 and a hearing with the OCC is scheduled to occur in March 2025. Subject to obtaining the required approvals from FERC and the OCC, PSO expects to close on the transaction by June 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.

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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 December 31, 2024, by year, for the five year period 2025-2029:

(a)In January 2025, I&M terminated a 481 MW and a 600 MW capacity purchase agreement.

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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 possibly financial condition. AEP is currently involved in the following key proceedings.

The following tables show the Registrants’ completed and pending base rate case proceedings in 2024. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

(a)A two-step increase in Indiana rates with a $28 million annual increase effective May 2024 with the remaining $15 million annual increase effective in January 2025 subject to I&M’s level of electric plant in service as of December 31, 2024 in comparison to I&M’s 2024 forecasted test year.

Pending Base Rate Case Proceedings

Other Significant Regulatory Matters

Ohio ESP Filings

In January 2023, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments, proposed new riders and the continuation and modification of certain existing riders, including the DIR, effective June 2024 through May 2030. The proposal includes a return on common equity of 10.65% on capital costs for certain riders. In June 2023, intervenors filed testimony opposing OPCo’s plan for various new riders and modifications to existing riders, including the DIR. In September 2023, OPCo and certain intervenors filed a settlement agreement with the PUCO addressing the ESP application. The settlement included a four year term from June 2024 through May 2028, an ROE of 9.7% and continuation of a number of riders including the DIR subject to revenue caps. In April 2024, the PUCO issued an order approving the settlement agreement. In May 2024, intervenors filed an application for rehearing with the PUCO on the approved settlement agreement and the PUCO denied the intervenors’ application for rehearing in June 2024.

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. In November 2021, SWEPCo and

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the PUCT submitted Petitions for Review with the Texas Supreme Court. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. In June 2023, the Texas Supreme Court denied SWEPCo’s request for rehearing and the case was remanded to the PUCT for future proceedings. In October 2023, SWEPCo filed testimony with the PUCT in the remanded proceeding recommending no refund or disallowance.

In December 2023, the PUCT approved a preliminary order stating the PUCT will not address SWEPCo’s request that would allow the PUCT to find cause to allow SWEPCo to exceed the Texas jurisdictional capital cost cap in the current remand proceeding. As a result of the PUCT’s approval of the preliminary order, SWEPCo recorded a pretax, non-cash probable disallowance of $86 million in the fourth quarter of 2023.

The PUCT’s December 2023 approval of the preliminary order determined that it will address, in the ongoing PUCT remand proceeding, any potential revenue refunds to customers that may be required by future PUCT orders. On March 1, 2024, SWEPCo filed supplemental direct testimony with the PUCT in response to the December 2023 preliminary order. On March 8, 2024, intervenors and the PUCT staff filed a motion with the PUCT to strike portions of SWEPCo’s October 2023 direct testimony and March 2024 supplemental direct testimony. On March 19, 2024, the ALJ granted portions of the motion, which included removal of testimony supporting SWEPCo’s position that refunds were not appropriate. On March 28, 2024, SWEPCo filed an appeal of the ALJ decision with the PUCT. In April 2024, intervenors and PUCT staff submitted testimony recommending customer refunds through December 2023 ranging from $149 million to $197 million, including carrying charges, with refund periods ranging from 18 months to 48 months. In May 2024, the PUCT denied SWEPCo’s appeal of the ALJ’s March 2024 decision. In the second quarter of 2024, based on the PUCT’s decision, SWEPCo recorded a one-time, probable revenue refund provision of $160 million, including interest, associated with revenue collected from February 2013 through December 2023. In June 2024, SWEPCo and parties to the remand proceeding reached an agreement in principle that would resolve all issues in the case. In October 2024, SWEPCo filed the settlement agreement with the PUCT. Under the settlement agreement, SWEPCo would refund, over a two-year period, $148 million, including interest, associated with revenue collected from February 2013 through December 2023 and remove AFUDC in excess of the Texas jurisdictional capital cost cap from rate base. In January 2025, the settlement agreement was approved by the PUCT.

FERC 2021 PJM and SPP Transmission Formula Rate Challenge

The Registrants transitioned to stand-alone treatment of NOLCs in its 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. Stand-alone treatment of the NOLCs for transmission formula rates increased the annual revenue requirements for years 2024, 2023, 2022 and 2021 by $52 million, $61 million, $69 million and $78 million, respectively.

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, in the third quarter of 2024, the AEP transmission owning subsidiaries within SPP provided a portion of the 2021 rate year refunds, with the remainder of the refunds expected to be provided in 2025. The AEP transmission owning subsidiaries within PJM are expected to provide their respective refunds for the 2021 rate year in 2025. 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 reflect a liability for the probable refund of all NOLC revenues included in transmission formula rates for years 2024, 2023, 2022 and 2021, with interest. The Registrants have not yet been directed to make cash refunds related to the 2024, 2023 or 2022 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 amounts expected to be refunded within one year which are reflected in Other Current Liabilities. Refunds

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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 the first half of 2025, subject to market conditions. As of December 31, 2024, regulatory asset balances expected to be recovered through securitization total $491 million and include: (a) $303 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) $57 million of under-recovered purchased power rider costs and (e) $2 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.

KPCo Fuel Adjustment Clause (FAC) Review

In December 2023, KPCo received intervenor testimony in its FAC review for the two-year period ending October 31, 2022, recommending a disallowance ranging from $44 million to $60 million of its total $432 million purchased power cost recoveries as a result of proposed modifications to the ratemaking methodology that limits purchased power costs recoverable through the FAC. In November 2024, KPCo and intervening parties entered into a settlement agreement whereby KPCo agreed to provide customer rate credits, which will reduce FAC costs otherwise recoverable in 2025 and 2026, for a combined $17 million over the periods January 2025 through April 2025 and January 2026 through April 2026 based on actual customer usage. In December 2024, the KPSC issued an order approving the settlement agreement without modification.

Ohio House Bill 6 (HB 6)

In July 2019, 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 July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a 501(c)(4) social welfare organization, in connection with an alleged racketeering conspiracy involving the adoption of HB 6. Certain defendants in that case had previously plead guilty and, in March 2023, a federal jury convicted Larry Householder and another individual of participating in the racketeering conspiracy. In February 2024, an Ohio grand jury indictment charged certain former FirstEnergy executives and the former PUCO Chairman and related entities with various crimes, including bribery. In January 2025, a federal grand jury indictment charged certain former FirstEnergy executives with a racketeering conspiracy based on similar allegations. In 2021, four AEP shareholders filed derivative actions purporting to assert claims on behalf of AEP against certain AEP officers and directors. In April 2024, AEP reached an agreement with the four shareholders to fully and finally resolve the derivative actions, and the settlement of those actions was approved in October 2024. See “Litigation Related to Ohio House Bill 6” section of Litigation below for additional information.

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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. To the extent that the law changes or OPCo: (a) is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032 or (b) is unable to recover costs of OVEC after 2030, it could reduce future net income and cash flows and impact financial condition.

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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 6 – Commitments, Guarantees and Contingencies for additional information.

Litigation Related to Ohio House Bill 6 (HB 6)

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and others relating to HB 6, AEP, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. Management does not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6.

In August 2020, an AEP shareholder filed a putative class action lawsuit in the U.S. District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. In December 2021, the district court issued an opinion and order dismissing the securities litigation complaint with prejudice, determining that the complaint failed to plead any actionable misrepresentations or omissions. The plaintiffs did not appeal the ruling.

In January 2021, an AEP shareholder filed a derivative action in the U.S. District Court for the Southern District of Ohio purporting to assert claims on behalf of AEP against certain AEP officers and directors. In February 2021, a second AEP shareholder filed a similar derivative action in the Court of Common Pleas of Franklin County, Ohio. In April 2021, a third AEP shareholder filed a similar derivative action in the U.S. District Court for the Southern District of Ohio and a fourth AEP shareholder filed a similar derivative action in the Supreme Court for the State of New York, Nassau County. These derivative complaints allege the officers and directors made misrepresentations and omissions similar to those alleged in the putative securities class action lawsuit filed against AEP. The derivative complaints (collectively, the “Derivative Actions”) together assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets, (c) unjust enrichment, (d) breach of duty for insider trading and (e) contribution for violations of sections 10(b) and 21D of the Securities Exchange Act of 1934; and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The court entered a scheduling order in the New York state court derivative action staying the case other than with respect to briefing the motion to dismiss. AEP filed substantive and forum-based motions to dismiss in April 2022. In June 2022, the Ohio state court entered an order continuing the stays of that case until the final resolution of the consolidated derivative actions pending in Ohio federal district court. In September 2022, the New York state court granted the forum-based motion to dismiss with prejudice and the plaintiff subsequently filed a notice of appeal with the New York appellate court. In January 2023, the New York plaintiff filed a motion to intervene in the pending Ohio federal court action and withdrew his appeal in New York. The two derivative actions pending in federal district court in Ohio have been consolidated and the plaintiffs in the consolidated action filed an amended complaint. AEP filed a motion to dismiss the amended complaint and subsequently filed a brief in opposition to the New York plaintiffs’ motion to intervene in the consolidated action in Ohio. In March 2023, the federal district court issued an order granting the motion to dismiss with prejudice and denying the New York plaintiffs’ motion to intervene. In April 2023, one of the plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Sixth Circuit of the Ohio federal district court order dismissing the consolidated action and denying the intervention.

In March 2021, AEP received a litigation demand letter from counsel representing a purported AEP shareholder. The litigation demand letter was directed to the Board of Directors of AEP (AEP Board) and contained factual allegations involving HB 6 that were generally consistent with those in the derivative litigation filed in state and federal court. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect. In April 2023, AEP received a litigation demand letter from counsel representing the purported AEP shareholder who had filed the dismissed derivative action in New York state court and unsuccessfully tried to intervene in the consolidated derivative actions in Ohio federal court the (Litigation Demand). The Litigation Demand is directed to the AEP Board and contains factual allegations involving HB 6 that are generally consistent with those in the Derivative Actions. The Litigation Demand requested, among other things, that the AEP Board undertake an independent investigation into alleged legal violations by certain current and former directors and officers, and that AEP commence a civil action asserting claims similar to the claims asserted in the Derivative Actions. The AEP Board considered the Litigation Demand and formed a committee of the Board (the Demand Review Committee) to investigate, review, monitor and analyze the Litigation Demand and make a recommendation to the AEP Board regarding a reasonable and appropriate response to the same.

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In April 2024, AEP reached an agreement with the four shareholders to fully and finally resolve the Derivative Actions and the Litigation Demand, and all claims asserted or that could have been asserted by any AEP shareholder based on the facts alleged, in the manner and upon the terms and conditions set forth in the settlement documents (the Settlement). In July 2024, the U.S. District Court preliminarily approved the Settlement. The Settlement includes a payment of $450 thousand for attorneys’ fees and the implementation of certain governance changes outlined in the Settlement, many of which previously had been put in place. The Settlement does not include any admission of liability. In October 2024, the District Court issued an Order and Judgment approving the Settlement and granted an Order of Dismissal with Prejudice. Under the Settlement, all Derivative Actions have been dismissed, the Litigation Demand has been withdrawn, and those matters and claims have been resolved pursuant to the terms of the Settlement.

In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing investigation. In January 2025, AEP and the SEC reached a settlement concluding and resolving the SEC’s investigation concerning AEP’s relationship with and statements about Empowering Ohio’s Economy, a 501(c)(4) organization and AEP’s related internal accounting and disclosure controls. Under the terms of the administrative order, in which AEP neither admits nor denies the SEC’s findings, AEP agreed to pay a civil penalty of $19 million and to cease and desist from committing or causing any violations and any future violations of the specified provisions of the federal securities laws. AEP recorded an accrual for the full amount of the penalty in the third quarter of 2024. The $19 million penalty is included in Other Operation expenses on AEP’s statements of income and in Other Current Liabilities on AEP’s balance sheet.

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 that is reasonably possible of occurring.

Litigation Regarding Justice Thermal Coal Contract

In December 2023, APCo filed a suit in the Franklin County Ohio Court of Common Pleas seeking a declaratory judgment confirming APCo’s right to terminate a long-term coal contract with Justice Thermal LLC (Justice Thermal) based on Justice Thermal’s failure to perform under the contract. APCo terminated that contract in January 2024, and in April 2024, APCo filed an amended complaint seeking a declaration that the termination was proper and also seeking damages for Justice Thermal’s breach of contract. Justice Thermal filed an answer and counterclaim in April 2024, contesting the validity of the contract termination and asserting counterclaims. The parties entered into a Settlement Agreement and Release pursuant to which the litigation was dismissed with prejudice in September 2024 and each party released the other from all claims relating to the contract or the litigation, and as a result this matter has been resolved.

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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 change in Presidential administrations.

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 December 31, 2024, 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 and (g) 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 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

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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. 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 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. Management will continue to monitor the outcome of this litigation and the development of SIPs 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.

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

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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, 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. Management cannot predict the outcome of that litigation. 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 AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.

AEP is committed to providing reliable affordable power to its customers. To achieve this, AEP and its subsidiaries routinely meet with state regulators and key stakeholders to understand their needs for both dispatchable and renewable generation resources. This process evaluates, amongst other things, future supply and demand fundamentals, the economic aspects of investments, grid reliability and resilience, regulations and evolving RTO requirements, the advancement of generation technologies, and market impacts and constraints. As part of the regulatory process, AEP routinely submits IRPs in various regulatory jurisdictions to address future generation needs. The objective of the IRPs is to recommend future generation and capacity resources that provide the most cost-efficient and reliable power to customers. AEP remains committed to making generation and capacity resource decisions that provide the most cost-efficient and reliable power to customers, irrespective of any specific carbon-reduction goal. Based on the assumptions used in the most recent analysis, AEP expects that its Scope 1 GHG emissions will be reduced by 80% by 2030 (from a 2005 baseline).

AEP’s GHG reduction efforts are predicated on the combined preferences of the eleven states that we operate in. AEP has made significant progress in reducing GHG emissions from its power generation fleet and while we aspire to be at net-zero Scope 1 and 2 emissions by 2045, our performance will ultimately be driven by the needs and desires of the states we serve. AEP is engaging with regulators and policymakers and our decisions around generation resources are reflected in the preferences of these states. AEP has embraced the advancement of low-carbon generation solutions where supported, which may include early-stage projects to bring small modular nuclear reactors to Virginia and Indiana as an example. Further advancement of affordable new generation technologies and a market for offsets, as well as continued alignment with our states, would be required to achieve net-zero emissions.

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. 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 2020, the Federal EPA revised the original CCR Rule to include a requirement that unlined CCR storage ponds cease operations and initiate closure by April 11, 2021. The revised rule provided two options by which facilities could continue to operate unlined CCR storage ponds.

The first option provided an extension of the date by which unlined ponds had to cease receipt of CCR, and required a satisfactory demonstration of the need for additional time to develop alternative ash disposal capacity.

The second option allowed a generating facility to seek an extension of time to continue operating existing unlined CCR impoundments without developing alternative CCR disposal, provided the facility commits to cease combustion of coal by a date certain. Under this option, a generating facility had until October 17, 2023 to cease coal-fired operations and to close CCR storage ponds 40 acres or less in size, or through October 17, 2028 for facilities with CCR storage ponds greater than 40 acres in size. Pursuant to this option, AEP has applied for an extension of time to keep using unlined CCR impoundments at the Welsh Plant and has committed to cease coal combustion at that plant by October 17, 2028. To date, the Federal EPA has not taken any action on the pending extension request for the Welsh Plant.

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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”). The Federal EPA is requiring that owners and operators of legacy surface impoundments comply with all of the existing 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. AEP evaluated the applicability of the rule to current and former plant sites and recorded incremental ARO in the second quarter of 2024, as shown in the table below, based on initial cost estimates primarily reflecting compliance with the rule through closure in place and future groundwater monitoring requirements pursuant to the revised CCR Rule.

(a)ARO is related to a legacy CCR surface impoundment or CCR management unit at an operating generation facility.

(b)ARO is related to a legacy CCR surface impoundment or CCR management unit at a retired generation facility and recognition of a regulatory asset in accordance with the accounting guidance for “Regulated Operations” is supported.

(c)ARO is related to a legacy CCR surface impoundment or CCR management unit and recognition of a regulatory asset in accordance with the accounting guidance for “Regulated Operations” is not yet supported.

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 rule with the U.S. Court of Appeals for the D.C. Circuit. One of the parties also filed a motion to stay the rule pending the outcome of the litigation. In November 2024, the court denied the stay motion. Management cannot predict the outcome of the litigation.

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

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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. Management cannot predict the outcome of the litigation.

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 December 31, 2024, 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 will request recovery including a weighted average cost of capital carrying charge through a future proceeding. 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 5 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.

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 year ended December 31, 2024 as compared to the year ended December 31, 2023. 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 years ended December 31, 2024 and 2023, see the discussions of Results of Operations by Registrant Subsidiary.

A detailed discussion of AEP’s 2023 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 2023 Annual Report on Form 10-K filed with the SEC on February 26, 2024.

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

See Note 9 - Business Segments for additional information on Earnings (Loss) Attributable to AEP Common Shareholders by segment.

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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 table presents 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 the impact of the remeasurement of excess ADIT in Arkansas and Michigan.

(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.

(f) Represents a provision for revenue refund associated with the Turk Plant as a result of a PUCT approved settlement agreement in January 2025.

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

(h) Represents employee severance charges and pension settlement expenses.

(i) Represents the impact of the Federal EPA’s revised CCR Rule.

(j) Represents an estimated loss contingency related to a previously disclosed SEC investigation which is non-deductible for tax purposes based on the IRC rules for fines and penalties.

(k) Represents the impact of the remeasurement of accumulated deferred income taxes as a result of enacted state tax legislation in Arkansas and Louisiana.

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(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 accumulated deferred income taxes - net operating loss carryforward in Virginia and West Virginia.

(d)Represents the impact of the disallowance of the recovery of certain deferred fuel costs in West Virginia.

(e)Represents the impact of the disallowance of certain capitalized costs associated with the Turk Plant.

(f)Represents the loss on the sale of the Competitive Contracted Renewable Portfolio and other related third-party transaction costs.

(g)Represents an adjustment to the loss on the expected sale of the Kentucky Operations which was terminated in April 2023 and other related third-party transaction costs.

(h)Represents the impact of recent legislation in Texas regarding recovery of certain employee incentives.

(i)Represents the impact of the FERC decision denying stand-alone treatment of NOLCs for transmission formula rates.

(j)Represents the impact of AEP's workforce reduction in 2023.

(k)Represents the impairment of AEP's investment in the NMRD joint venture.

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(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 third-party transaction costs due to the unregulated renewable sales process.

(d)Includes a $363.3 million loss on the expected sale of the Kentucky operations and other related third-party transaction costs.

(e)Represents the impact of the impairment and disposition of AEP's investment in the Flat Ridge 2 wind farm joint venture.

(f)Represents the gain on the sale of certain mineral rights.

(g)Represents the impact of the Virginia Supreme Court opinion on AEP's appeal of Appalachian Power’s 2017-2019 Triennial Review.

(h)Represents the impact of mark-to-market on certain investments.

(i)Represents the impact of out-of-period adjustments related to accumulated deferred income taxes.

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VERTICALLY INTEGRATED UTILITIES

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

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.

(a)Heating degree days are calculated on a 55 degree temperature base.

(b)Normal Heating/Cooling represents the thirty-year average of degree days.

(c)Cooling degree days are calculated on a 65 degree temperature base.

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Reconciliation of Year Ended December 31, 2023 to Year Ended December 31, 2024

Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities

(in millions)

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

•Retail Revenues increased $71 million primarily due to the following:

•A $114 million increase in rates at APCo due to the 2020-2022 Virginia Triennial Review.

•A $99 million increase in weather-related usage primarily in the residential class driven by a 14% increase in cooling degree days.

•A $66 million increase in base rate and rider revenues at PSO.

•A $64 million increase in rider revenues at KPCo.

•A $63 million increase in rider revenues at APCo and WPCo.

These increases were partially offset by:

•A $192 million decrease in fuel revenues primarily due to lower authorized fuel rates at PSO.

•A $148 million decrease at SWEPCo due to a revenue refund associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.

•Off-system Sales decreased $8 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales at I&M.

•Transmission Revenues increased $58 million primarily due to continued investment in transmission assets.

•Other Revenues increased $26 million primarily due to pole attachment revenue primarily at APCo and revenues at PSO from a customer project to enhance transmission resiliency.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $354 million primarily due to decreases at APCo, PSO and SWEPCo.

•Other Operation and Maintenance expenses increased $317 million primarily due to the following:

•A $154 million increase in PJM and SPP transmission services.

•A $100 million increase in employee-related expenses including a $76 million increase associated with the voluntary severance program that occurred in the second quarter of 2024.

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•Asset Impairments and Other Related Charges decreased $72 million primarily due to the following:

•An $86 million decrease at SWEPCo due to the probable disallowance of Turk Plant capitalized AFUDC in excess of the Texas jurisdictional capital cost cap as a result of the PUCT’s December 2023 preliminary order in the 2012 Texas Base Rate Case.

This decrease was partially offset by:

•A $13 million increase due to the Federal EPA’s revised CCR rules.

•Depreciation and Amortization expenses increased $94 million primarily due to the following:

•A $47 million increase at SWEPCo primarily due to an increase in amortization of regulatory assets and a higher depreciable base, partially offset by the recognition of a regulatory asset related to NOLCs.

•A $31 million increase at APCo primarily due to a higher depreciable base.

•A $17 million increase at PSO primarily due to a higher depreciable base, implementation of new rates and the amortization of regulatory assets related to NCWF.

•Taxes Other Than Income Taxes increased $23 million primarily due to increased property taxes at PSO and I&M and an increase in Virginia state minimum taxes at APCo, partially offset by a decrease in property taxes at SWEPCo.

•Allowance for Equity Funds Used During Construction increased $6 million primarily due to higher CWIP and AFUDC equity rates.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $57 million primarily due to an increase in loss amortization for the plans and a plan remeasurement triggered by settlements related to the voluntary severance program, partially offset by lower interest costs due to lower discount rates.

•Interest Expense decreased $40 million primarily due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.

•Income Tax Benefit increased $237 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 rate making.

•A $69 million increase due to estimated Nuclear PTCs at I&M.

•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.

These increases were partially offset by:

•An $82 million decrease due to a decrease in amortization of Excess ADIT.

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TRANSMISSION AND DISTRIBUTION UTILITIES

(a)Represents energy delivered to distribution customers.

(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold into PJM.

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.

(a)Heating degree days are calculated on a 55 degree temperature base.

(b)Normal Heating/Cooling represents the thirty-year average of degree days.

(c)Eastern Region cooling degree days are calculated on a 65 degree temperature base.

(d)Western Region cooling degree days are calculated on a 70 degree temperature base.

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Reconciliation of Year Ended December 31, 2023 to Year Ended December 31, 2024

Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities

(in millions)

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

•Retail Revenues increased $115 million primarily due to the following:

•A $428 million increase in rider revenues.

•A $41 million increase in weather-related usage driven by a 54% increase in cooling degree days and a 3% increase in heating degree days in Ohio.

•A $16 million increase in weather-normalized revenues due to increased load across all classes in Texas.

•An $11 million increase in revenue from the base rate case in Texas.

These increases were partially offset by:

•A $387 million decrease due to lower prices and lower customer participation in OPCo’s SSO.

•Off-system Sales decreased $8 million primarily due to 2023 PJM settlements related to winter storm Elliott.

•Transmission Revenues increased $55 million primarily due to the following:

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

•A $12 million increase due to increased load in Texas.

•Other Revenues increased $32 million primarily due to the following:

•A $47 million increase due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

This increase was partially offset by:

•A $20 million decrease in recoverable sales of renewable energy credits in Ohio.

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

•Purchased Electricity for Resale expenses decreased $317 million primarily due to the following:

•A $398 million decrease in recoverable auction purchases primarily due to lower prices and lower volumes driven by lower customer participation in OPCo’s SSO.

•A $28 million decrease in recoverable alternative energy rider expenses in Ohio.

These decreases were partially offset by:

•A $110 million increase in recoverable OVEC costs.

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•Purchased Electricity from AEP Affiliates expenses increased $11 million primarily due to increased recoverable purchases in OPCo’s SSO auction.

•Other Operation and Maintenance expenses increased $218 million primarily due to the following:

•A $95 million increase in recoverable transmission expenses.

•A $35 million increase in employee-related expenses due to the voluntary severance program that occurred in the second quarter of 2024.

•A $33 million increase in distribution expenses in Ohio primarily due to recoverable storm restoration costs and recoverable vegetation management expenses.

•A $28 million increase due to a prior year decrease in expenses driven by legislation passed in Texas in May 2023 allowing employee financially based incentives to be recovered.

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

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

•Depreciation and Amortization expenses increased $95 million primarily due to a higher depreciable base in Ohio and Texas and an increase in recoverable rider depreciable assets in Ohio.

•Taxes Other Than Income Taxes increased $56 million primarily due to the following:

•A $42 million increase due to higher property taxes driven by additional investments in transmission and distribution assets and tax rate changes in Ohio.

•An $11 million increase in state excise taxes due to increased billed KWhs in 2024 resulting in a higher tax burden in Ohio.

•Other Income increased $7 million primarily due to an increase in interest income due to higher advances to affiliates.

•Allowance for Equity Funds Used During Construction increased $24 million due to a higher AFUDC base in Ohio and Texas and AFUDC equity rates in Ohio.

•Non-Service Cost Components of Net Period Benefit Cost increased $25 million primarily due to an increase in loss amortization for the plans and a plan remeasurement triggered by settlements related to the voluntary severance program, partially offset by lower interest costs due to lower discount rates.

•Interest Expense increased $42 million primarily due to higher debt balances and interest rates.

•Income Tax Expense increased $14 million primarily due to an increase in pretax book income in Texas.

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AEP TRANSMISSION HOLDCO

Summary of Investment in Transmission Assets for AEP Transmission Holdco

Reconciliation of Year Ended December 31, 2023 to Year Ended December 31, 2024

Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco

(in millions)

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

•Transmission Revenues increased $222 million primarily due to continued investment in transmission assets.

Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiaries changed between years as follows:

•Other Operation and Maintenance expenses increased $21 million primarily due to an $18 million increase in employee-related expenses driven by an $11 million increase associated with the voluntary severance program that occurred in the second quarter of 2024.

•Depreciation and Amortization expenses increased $37 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $25 million primarily due to higher property taxes driven by increased transmission investment.

•Allowance for Equity Funds Used During Construction increased $6 million primarily due to a higher AFUDC base.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $8 million primarily due to an increase in loss amortization for the plans and a plan remeasurement triggered by settlements related to the voluntary severance program, partially offset by lower interest costs due to lower discount rates.

•Interest Expense increased $20 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $49 million primarily due to the following:

•A $29 million increase due to an increase in pretax book income.

•A $22 million increase in state taxes primarily driven by favorable deferred state tax remeasurements in 2023.

•Equity Earnings of Unconsolidated Subsidiaries increased $16 million primarily due to higher pretax earnings at ETT.

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GENERATION & MARKETING

Reconciliation of Year Ended December 31, 2023 to Year Ended December 31, 2024

Earnings Attributable to AEP Common Shareholders from Generation & Marketing

(in millions)

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

•Merchant Generation decreased $14 million primarily due to lower realized prices in 2024.

•Renewable Generation decreased $69 million primarily due to the sale of the competitive contracted renewables portfolio in August 2023 and the sale of Onsite Partners in September 2024.

•Retail, Trading and Marketing increased $496 million primarily due to a $314 million unrealized loss on economic hedge activity in 2023 and a $128 million unrealized gain on economic hedge activity in 2024 driven by changes in commodity prices.

Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiaries changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $55 million primarily due to an increase in energy costs in 2024.

•Asset Impairments and Other Related Charges increased $76 million due to the Federal EPA’s revised CCR Rules.

•Loss on the Sale of the Competitive Contracted Renewables Portfolio decreased $93 million due to the pretax loss on the sale in August 2023.

•Depreciation and Amortization expenses decreased $22 million primarily due to the sale of the competitive contracted renewables portfolio in August 2023 and the sale of Onsite Partners in September 2024.

•Interest and Investment Income decreased $11 million primarily due to the sale of the competitive contracted renewables portfolio in August 2023 and the sale of Onsite Partners in September 2024.

•Interest Expense decreased $59 million primarily due to lower advances from affiliates.

•Income Tax Expense increased $149 million primarily due to the following:

•A $97 million increase due to an increase in pretax book income.

•A $46 million increase due to a decrease in PTCs.

•Equity Earnings of Unconsolidated Subsidiaries increased $17 million primarily due to a $19 million impairment of AEP’s investment in NMRD in 2023.

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CORPORATE AND OTHER

2024 Compared to 2023

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $258 million in 2023 to a loss of $291 million in 2024 primarily due to:

•A $69 million decrease in interest income primarily due to lower advances to affiliates.

•A $28 million decrease due to a prior-year adjustment driven by the termination of the sale of the Kentucky Operations.

•A $19 million expense recorded in 2024 associated with the SEC investigation.

These decreases in earnings were partially offset by:

•A $68 million decrease in Income Tax Expense primarily due to a decrease in state taxes.

•A $23 million decrease in corporate expenses.

AEP CONSOLIDATED INCOME TAXES

2024 Compared to 2023

•Income Tax Benefit increased $94 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 rate making.

•A $69 million increase due to estimated Nuclear PTCs.

•A $32 million increase 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 March 2024 denial of SWEPCo's request to allow the merchant portion of the Turk Plant to serve Arkansas customers.

These increases were partially offset by:

•A $140 million decrease due to an increase in pretax book income.

•A $50 million decrease due to a decrease in amortization of Excess ADIT.

FINANCIAL CONDITION

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

SIGNIFICANT CASH REQUIREMENTS

AEP’s contractual cash obligations include amounts reported on the balance sheets and other obligations disclosed in the footnotes. It is anticipated that these obligations will be satisfied through a combination of cash flows from operations, long-term debt issuances, short-term debt through AEP’s Commercial Paper Program or bank term loans, proceeds from the announced agreement related to the disposition of a 19.9% noncontrolling equity interest in IMTCo and OHTCo and the use of the ATM Program or other equity issuances.

Capital Expenditures

Continued capital investments reflect AEP’s commitment to enhance service and deliver safe, reliable power to customers. In November 2024, AEP announced a $54 billion capital plan for 2025-2029 driven by transmission and distribution infrastructure upgrades and new generation to support anticipated load growth. See “Budgeted Capital Expenditures” herein, for additional information.

Long-term Debt

Long-term debt maturities, including interest, represent a significant cash requirement for AEP and the Registrant Subsidiaries. See Note 15 - Financing Activities for additional information relating to the Registrant Subsidiaries’ long-term debt outstanding as of December 31, 2024, the weighted-average interest rate applicable to each debt category and a schedule of debt maturities over the next five years.

Other Significant Cash Requirements

Operating and finance leases represent a significant component of funding requirements for AEP and the Registrant Subsidiaries. See Note 13 - Leases for additional information.

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AEP subsidiaries have substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. See Note 6 - Commitments, Guarantees and Contingencies for additional information.

As of December 31, 2024, AEP expected to make contributions to the pension plans totaling $101 million in 2025. Estimated contributions of $100 million in 2026 and $103 million in 2027 may vary significantly based on market returns, changes in actuarial assumptions and other factors. Based upon the projected benefit obligation and fair value of assets available to pay pension benefits, the pension plans were 95% funded as of December 31, 2024. See “Estimated Future Benefit Payments and Contributions” section of Note 8 for additional information.

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 security reserves. There is no collateral held in relation to any guarantees in excess of the ownership percentages. In the event any letters of credit are drawn, there is no recourse to third-parties. See “Letters of Credit” section of Note 6 for additional information.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

AEP’s ratio of debt-to-total capital decreased from 63.0% to 62.6% as of December 31, 2023 and December 31, 2024, respectively, primarily due to an increase in earnings and equity issued under the ATM program in 2024, partially offset by an increase in long-term debt to support distribution and transmission growth 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 December 31, 2024, AEP had $6 billion in revolving credit facilities to support its commercial paper program. Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, long-term asset securitizations, leasing agreements, hybrid securities or common stock. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that there is an increase in interest rates, it could reduce future net income and cash flows and impact financial condition. In January 2025, KPCo entered into a term loan of $150 million, due in February 2026, to address short-term liquidity needs.

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 year ended December 31, 2024.

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Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of December 31, 2024, available liquidity was approximately $4.6 billion as illustrated in the table below:

(a)In March 2024, AEP increased its $4 billion Revolving Credit Facility to $5 billion and extended the maturity date from March 2027 to March 2029. Also, in March 2024, AEP extended the maturity date of its $1 billion Revolving Credit Facility from March 2025 to March 2027.

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 2024 was $2.9 billion.  The average amount of commercial paper outstanding as of December 31, 2024 was $1.5 billion. The weighted-average yield for AEP’s commercial paper during 2024 was 5.39%.

Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. As of December 31, 2024, AEP issued 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 December 31, 2024 was $238 million with maturities ranging from January 2025 to November 2025.

Financing Plan

As of December 31, 2024, AEP had $3.3 billion of long-term debt due within one year. This included $580 million of Pollution Control Bonds with mandatory tender dates and credit support for variable interest rates that requires the debt be classified as current and $155 million of securitization bonds and DCC Fuel notes.  Management plans to refinance the majority of the maturities due within one year on a long-term basis.

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 December 31, 2024, 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 December 31, 2024, this contractually-defined percentage was 59.3%. 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.

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

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

ATM Program

AEP participates in an ATM offering 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 December 31, 2024, approximately $1.3 billion of equity is available for issuance under the ATM offering program. See Note 15 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.93 per share in January 2025.  Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 15 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.

Supply Chain Disruption and Inflation

The Registrants have experienced certain supply chain disruptions driven by several factors including international tensions and the ramifications of regional conflict, inflation, labor shortages in certain trades and shortages in the availability of certain raw materials. These supply chain disruptions 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. Management has implemented risk mitigation strategies seeking to limit the impacts of these supply chain disruptions. Forecasted load growth 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.

The United States economy has been in an elevated inflationary environment. A prolonged continuation or a further increase in the severity of supply chain and inflationary disruptions could result in 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.

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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)Includes Depreciation and Amortization, Deferred Income Taxes, Loss on the Expected Sale of the Kentucky Operations, Loss on the Sale of the Competitive Contracted Renewables Portfolio, Asset Impairments and Other Related Charges, Impairment of Equity Method Investment, Allowance for Equity Funds Used During Construction, Amortization of Nuclear Fuel, Gain on the Sale of Mineral Rights and Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset.

(b)Includes Change in Regulatory Assets.

2024 Compared to 2023

Net Cash Flows from Operating Activities increased by $1.8 billion primarily due to the following:

•A $1.2 billion increase in cash from the Change in Certain Components of Working Capital. The increase is primarily due to a decrease in fuel, material and supplies driven by lower coal inventory on hand, employee-related benefits, proceeds received from the sale of transferable tax credits and the timing of accounts payable. These increases were partially offset by the timing of accounts receivable collections.

•A $751 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

•A $277 million increase in cash from Changes in Other Noncurrent Liabilities. The 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 in addition to a decrease in ARO settlements in 2024. See Note 5 - Effects of Regulation and Note 19 - Property, Plant and Equipment for additional information.

•A $259 million increase in cash from Change in Other Noncurrent Assets primarily due to incremental other operation and maintenance storm restoration expenses incurred in several jurisdictions in addition to timing differences in collections from customers under rate rider mechanisms. See Note 4 - Rate Matters and Note 5 - Effects of Regulation for additional information.

These increases in cash were partially offset by:

•A $616 million decrease in cash primarily due to the timing of fuel and purchased power revenues and expenses.

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Investing Activities

2024 Compared to 2023

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

•A $979 million decrease in Proceeds from Sale of Assets, primarily due to the sale of the competitive contracted renewables portfolio in 2023, partially offset by the sale of AEP Onsite Partners in 2024.

•A $252 million increase in Construction Expenditures, primarily due to increases in Corporate and Other of $430 million driven by expenditures for fuel cell generation assets partially offset by decreases in Transmission and Distribution Utilities of $124 million and Vertically Integrated Utilities of $87 million.

•A $244 million increase in Acquisition of Renewable Energy Facilities.

These increases in cash used were partially offset by:

•A $114 million increase in Proceeds from the Sale of AEP’s Equity Investment in NMRD.

See Note 7 - Acquisitions, Dispositions and Impairments for additional information.

Financing Activities

2024 Compared to 2023

Net Cash Flows from Financing Activities decreased by $418 million primarily due to the following:

•A $489 million increase in retirements of long-term debt.

•A $448 million decrease in issuances of common stock primarily under AEP’s ATM program.

•A $346 million decrease in issuances of long-term debt.

•A $144 million decrease due to an increase in dividends paid on common stock.

These decreases in cash were partially offset by:

•A $976 million increase due to changes in short-term debt.

The following financing activities occurred during 2024:

AEP Common Stock:

•During 2024, AEP issued 6.7 million shares of common stock under the ATM offering program, incentive compensation, employee saving and dividend reinvestment plans. See “Common Stock” section of Note 15 for additional information. AEP received net proceeds of $552 million related to these issuances.

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Debt:

•During 2024, AEP issued approximately $5.1 billion of long-term debt, including $2.8 billion of senior unsecured notes at interest rates ranging from 5.15% to 5.82%, $1 billion of junior subordinated notes at interest rates ranging from 6.95% to 7.05%, $530 million of notes payable at interest rates ranging from 6.41% to 6.89%, $385 million of pollution control bonds at interest rates ranging from 3.2% to 3.75%, $337 million of securitization bonds at an interest rate of 4.88% and $133 million of other debt at various interest rates.  The proceeds from these issuances were primarily used to fund long-term debt maturities, construction programs and for working capital needs.

•During 2024, AEP entered into interest rate derivatives with notional amounts totaling $600 million that were designated as cash flow hedges.  During 2024, settlements of AEP’s interest rate derivatives resulted in net cash paid of $49 million for derivatives designated as fair value hedges and net cash received of $4 million designated as cash flow hedges.  As of December 31, 2024, AEP had a total notional amount of $950 million of outstanding interest rate derivatives designated as fair value hedges.

See “Long-term Debt Subsequent Events” section of Note 15 for Long-term debt and other securities issued, retired and principal payments made after December 31, 2024 through February 13, 2025, the date that the 10-K was issued.

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. The estimated capital expenditures by Business Segment are as follows:

(a)Amount primarily consists of facilities, software and telecommunications.

The 2025 estimated capital expenditures by Registrant Subsidiary are as follows:

(a) Amount primarily consists of facilities, software and telecommunications.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies.  Management considers an accounting estimate to be critical if:

•It requires assumptions to be made that were uncertain at the time the estimate was made; and

•Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition.

Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosures relating to them.

Management believes that the current assumptions and other considerations used to estimate amounts reflected in the financial statements are appropriate.  However, actual results can differ significantly from those estimates.

The sections that follow present information about critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.

Regulatory Accounting

Nature of Estimates Required

The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.

The Registrants recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation.  Specifically, the timing of expense and income recognition is matched with regulated revenues.  Liabilities are also recorded for refunds, or probable refunds, to customers that have not been made.

Assumptions and Approach Used

When incurred costs are probable of recovery through regulated rates, regulatory assets are recorded on the balance sheets.  Management reviews the probability of recovery at each balance sheet date and whenever new events occur.  Similarly, regulatory liabilities are recorded when a determination is made that a refund is probable or when ordered by a commission.  Examples of new events that affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation.  The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs as well as the return of revenues, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates.  If recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings.  A write-off of regulatory assets or establishment of a regulatory liability may also reduce future cash flows since there will be no recovery through regulated rates.

Effect if Different Assumptions Used

A change in the above assumptions may result in a material impact on net income.  See Note 5 - Effects of Regulation for additional information related to regulatory assets and regulatory liabilities.

Revenue Recognition – Unbilled Revenues

Nature of Estimates Required

AEP recognizes revenues from customers as the performance obligations of delivering energy to customers are satisfied.  The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded.  This estimate is reversed in the following month and actual revenue is recorded based on meter readings.  PSO and SWEPCo do not include the fuel portion in unbilled revenue in accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas.

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Accrued unbilled revenues for the Vertically Integrated Utilities segment were $351 million and $288 million as of December 31, 2024 and 2023, respectively. The changes in unbilled electric utility revenues for AEP’s Vertically Integrated Utilities segment were $63 million, $(66) million and $108 million for the years ended December 31, 2024, 2023 and 2022, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather, rates and usage.

Accrued unbilled revenues for the Transmission and Distribution Utilities segment were $199 million and $191 million as of December 31, 2024 and 2023, respectively. The changes in unbilled electric utility revenues for AEP’s Transmission and Distribution Utilities segment were $8 million, $(30) million and $49 million for the years ended December 31, 2024, 2023 and 2022, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather, rates and usage.

Accrued unbilled revenues for the Generation & Marketing segment were $121 million and $111 million as of December 31, 2024 and 2023, respectively. The changes in unbilled electric utility revenues for AEP’s Generation & Marketing segment were $10 million, $2 million and $(1) million for the years ended December 31, 2024, 2023 and 2022, respectively.

Assumptions and Approach Used

For each Registrant except AEPTCo, the monthly estimate for unbilled revenues is based upon a primary computation of net generation (generation plus purchases less sales) less the current month’s billed KWhs and estimated line losses, plus the prior month’s unbilled KWhs. However, due to the potential for meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon an allocation of billed KWhs to the current month and previous month, on a billing cycle-by-cycle basis, and by dividing the current month aggregated result by the billed KWhs. The two methodologies are evaluated to confirm that they are not statistically different.

For AEP’s Generation & Marketing segment, management calculates unbilled revenues based on a primary computation of load as provided by PJM less the current month’s billed KWhs and estimated line losses, plus the prior month’s unbilled KWhs. However, due to the potential for meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon using the most recent historic daily activity on a per contract basis. The two methodologies are evaluated to confirm that they are not statistically different.

Effect if Different Assumptions Used

If the two methodologies used to estimate unbilled revenue are statistically different, a limiter adjustment is made to bring the primary computation within one standard deviation of the secondary computation. Additionally, significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the estimate of unbilled revenue.

Accounting for Derivative Instruments

Nature of Estimates Required

Management considers fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates.  These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.

Assumptions and Approach Used

The Registrants measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based primarily on exchange prices and broker quotes.  If a quoted market price is not available, the fair value is estimated based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions.  Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment.  These uncertainties include forward market price assumptions.

The Registrants reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality.  Liquidity adjustments are calculated by utilizing bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time.  Credit adjustments on risk management contracts are calculated using estimated default probabilities and recovery rates relative to the counterparties or counterparties with similar credit profiles and contractual netting agreements.

With respect to hedge accounting, management assesses hedge effectiveness and evaluates a forecasted transaction’s probability of occurrence within the specified time period as provided in the original hedge documentation.

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Effect if Different Assumptions Used

There is inherent risk in valuation modeling given the complexity and volatility of energy markets.  Therefore, it is possible that results in future periods may be materially different as contracts settle.

The probability that hedged forecasted transactions will not occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into Operating Income.

For additional information see Note 10 - Derivatives and Hedging and Note 11 - Fair Value Measurements.  See “Fair Value Measurements of Assets and Liabilities” section of Note 1 for AEP’s fair value calculation policy.

Long-Lived Assets

Nature of Estimates Required

In accordance with the requirements of “Property, Plant and Equipment” accounting guidance and “Regulated Operations” accounting guidance, the Registrants evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable. Such events or changes in circumstance include planned abandonments, probable disallowances for rate-making purposes of assets determined to be recently completed plant and assets that meet the held-for-sale criteria.  The Registrants utilize a group composite method of depreciation to estimate the useful lives of long-lived assets.

An impairment evaluation of a long-lived, held and used asset may result from an abandonment, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses.  If the book value of the asset is not recoverable through estimated, future undiscounted cash flows, the Registrants record an impairment to the extent that the fair value of the asset is less than its book value.  Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets and developing the non-discounted and discounted future cash flows (used to estimate fair value in the absence of market-based value, in some instances) associated with the asset.  Assets held for sale must be measured at the lower of the book value or fair value less cost to sell. An impairment is recognized if an asset’s fair value less costs to sell is less than its book value. Any impairment charge is recorded as a reduction to earnings.

Assumptions and Approach Used

The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, the Registrants estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals.  Cash flow estimates are based on relevant information available at the time the estimates are made.  Estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.  Also, when measuring fair value, management evaluates the characteristics of the asset or liability to determine if market participants would take those characteristics into account when pricing the asset or liability at the measurement date.  Such characteristics include, for example, the condition and location of the asset or restrictions on the use of the asset.  The Registrants perform depreciation studies that include a review of any external factors that may affect the useful life to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions for regulated assets.  The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Effect if Different Assumptions Used

In connection with the evaluation of long-lived assets in accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the fair value of the asset can vary if different estimates and assumptions are used in the applied valuation techniques.  Estimates for depreciation rates contemplate the history of interim capital replacements and the amount of salvage expected.  In cases of impairment, the best estimate of fair value was made using valuation methods based on the most current information at that time.  Differences in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, the timing and terms of the transactions and management’s analysis of the benefits of the transaction.

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Pension and OPEB

AEPSC maintains a qualified, defined benefit pension plan (Qualified Plan), which covers substantially all nonunion and certain union employees, and unfunded, non-qualified supplemental plans (Nonqualified Plans) to provide benefits in excess of amounts permitted under the provisions of the tax law for participants in the Qualified Plan (collectively the Pension Plans).  AEPSC also sponsors OPEB plans to provide health and life insurance benefits for retired employees.  The Pension Plans and OPEB plans are collectively referred to as the Plans.

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.  See Note 8 - Benefit Plans for information regarding costs and assumptions for the Plans.

The following table shows the net periodic cost (credit) of the Plans:

The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets.  In developing the expected long-term rate of return assumption for 2025, management evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions.  Management also considered historical returns of the investment markets and tax rates which affect a portion of the OPEB plans’ assets.  Management anticipates that the investment managers employed for the Plans will invest the assets to generate future returns averaging 7% for the Qualified Plan and 6.5% for the OPEB plans.

The expected long-term rate of return on the Plans’ assets is based on management’s targeted asset allocation and expected investment returns for each investment category.  Assumptions for the Plans are summarized in the following table:

Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation.  Management believes that 7% for the Qualified Plan and 6.5% for the OPEB plans are reasonable estimates of the long-term rate of return on the Plans’ assets.  The Pension Plans’ assets had an actual gain of 2.59% and an actual gain of 9.50% for the years ended December 31, 2024 and 2023, respectively.  The OPEB plans’ assets had an actual gain of 8.98% and an actual gain of 15.48% for the years ended December 31, 2024 and 2023, respectively.  Management will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.

AEP bases the determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.  Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.  As of December 31, 2024, AEP had cumulative gains of approximately $529 million for the Qualified Plan that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized market-related net actuarial gains may result in decreases in the future pension costs depending on several factors, including whether such gains at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance.

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The method used to determine the discount rate that AEP utilizes for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.  The discount rate as of December 31, 2024 under this method was 5.65% for the Qualified Plan, 5.6% for the Nonqualified Plans and 5.6% for the OPEB plans.  Due to the effect of the unrecognized net actuarial losses and based on an expected rate of return, discount rates and various other assumptions, management estimates costs (credits) for the Pension Plans will approximate $43 million, $99 million and $139 million in 2025, 2026 and 2027, respectively.  Based on an expected rate of return discount rate and various other assumptions, management estimates OPEB plan credits will approximate $78 million, $74 million and $80 million in 2025, 2026 and 2027, respectively. Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans.  The actuarial assumptions used may differ materially from actual results.  The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below.

The value of AEP’s Pension Plans’ assets is $3.7 billion as of December 31, 2024 and $4.1 billion as of December 31, 2023.  During 2024, the Qualified Plan paid $219 million and the Nonqualified Plans paid $5 million in benefits to plan participants.  The value of AEP’s OPEB plans’ assets increased to $1.8 billion as of December 31, 2024 from $1.7 billion as of December 31, 2023 primarily due to positive investment returns. During 2024, the OPEB plans paid $106 million in benefits to plan participants.

Nature of Estimates Required

AEPSC sponsors pension and OPEB plans in various forms covering all employees who meet eligibility requirements.  These benefits are accounted for under “Compensation” and “Plan Accounting” accounting guidance.  The measurement of pension and OPEB obligations, costs and liabilities is dependent on a variety of assumptions.

Assumptions and Approach Used

The critical assumptions used in developing the required estimates includes discount rate, compensation increase rate, cash balance crediting rate, health care cost trend rate and expected return on plan assets. Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.

Effect if Different Assumptions Used

The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants.  These differences may result in a significant impact to the amount of pension and OPEB expense recorded.  If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

NA    Not applicable.

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Asset Retirement Obligations – Impact of the 2024 CCR Rule

Nature of Estimates Required

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 as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land. Accounting for the incremental asset retirement obligation arising from the revised CCR Rule requires significant judgment by management due to the significant measurement uncertainty in estimating the incremental liability. As a result of the rule, AEP recorded an incremental ARO of $674 million in the second quarter of 2024.

Assumptions and Approach Used

AROs are computed as the present value of the estimated costs associated with the future retirement of an asset and are recorded in the period in which the liability is incurred. Projections of the timing and amounts of future cash outlays are based on estimation of the extent and quantity of coal ash present at sites, projections of the when and how the liabilities will be remediated as well as the rate at which costs will escalate over time and discount rate, which may change significantly over time.

Effect if Different Assumptions Used

As further groundwater monitoring and other analysis is performed, management expects to refine the assumptions and underlying cost estimates used in recording the incremental asset retirement obligation arising from the revised CCR Rule. The estimated liability can significantly change if there are changes in the impacted coal ash site acreage inputs or if refinements in the assumptions over the remediation costs for legacy CCR surface impoundments and CCR management units, including assumptions over future groundwater monitoring requirements vary from the initial estimates. These future changes could have a material impact on the ARO and materially reduce future net income, cash flows and financial condition if AEP cannot ultimately recover these additional costs of compliance. See Note 6 – Commitments, Guarantees and Contingencies and Note 19 – Property, Plant and Equipment for additional information related to AROs and the CCR Rule.

ACCOUNTING STANDARDS

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

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