AEP Texas Inc.

EXECUTIVE OVERVIEW

AEP CONSOLIDATED RESULTS OF OPERATIONS

Earnings Attributable to AEP Common Shareholders increased from $960 million in 2024 to $972 million in 2025 primarily due to:

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

•Favorable rate proceedings in AEP’s various jurisdictions.

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

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

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

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

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

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

•An increase in sales volumes driven by favorable weather.

•Favorable rate proceedings in AEP’s various jurisdictions.

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

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

Non-GAAP Financial Measures

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

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

Reconciliation of Reported GAAP Earnings to Operating Earnings

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

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

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

(c)Represents a true-up of the reduction in regulatory assets for OVEC-related purchased power costs through August 2025 as a result of approved legislation in Ohio.

(d)Represents an estimated loss contingency related to a previously disclosed SEC investigation.

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

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

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

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

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

(f)Represents the impact of the remeasurement of Excess ADIT in Arkansas and Michigan as a result of the denial of SWEPCo’s request regarding the Turk Plant by the APSC and the approved treatment of stand-alone NOLCs by the MPSC.

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

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

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

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

(k)Represents employee severance charges.

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

(m)Represents an estimated loss contingency related to a previously disclosed SEC investigation.

RECENT DEVELOPMENTS AND TRANSACTIONS

Customer Demand

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

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

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

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

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

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

Large Load/Data Center Tariffs

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

In June 2025, Texas Senate Bill 6 (SB 6) became effective and was signed into law by the Governor of Texas. SB 6 establishes standards for connecting large load customers within ERCOT in a way that supports business development in Texas while minimizing the potential for stranded infrastructure costs. The new legislation establishes criteria for new large load interconnections and directs the PUCT to ensure that these large load customers pay a reasonable share of allocated transmission costs.

PSO New Generation Resources

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

New Generation to Support Reliability

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

Significant Approved Renewable Generation Filings

AEP has received regulatory approvals from various state regulatory commissions to acquire approximately 1,826 MWs of owned renewable generation facilities, totaling approximately $4.5 billion. The estimated cost of these facilities is included in the Budgeted Capital Expenditures disclosure included in the Financial Condition section below. In addition, AEP has received regulatory approvals for 1,059 MWs of renewable PPAs. The recently enacted OBBBA legislation is not expected to affect the eligibility of these generation facilities for federal tax incentives. The following table summarizes regulatory approvals received for active renewable projects as of September 30, 2025:

(a)APCo has 344 MWs of wind capacity under construction.

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

Natural Gas Generation

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

In February 2025, I&M filed an application with the IURC to acquire the Oregon Generation Plant (Oregon), an 870 MW combined-cycle power generation facility located near Toledo, Ohio. In April 2025, I&M submitted a FERC 203 application for the acquisition. If approved, the project will help I&M address increasing capacity and power needs. In August 2025, I&M reached a unanimous settlement in the filing submitted to the IURC with intervening parties approving the acquisition of the Oregon facility and cost recovery. The IURC will issue an order on I&M’s settlement filing in the fourth quarter of 2025. I&M expects to close on the transaction in the first quarter of 2026.

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

Significant Generation Requests for Proposal (RFP)

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

(a)RFP is seeking 1,500 MWs of SPP accredited capacity and associated energy through an all-source solicitation that was negotiated and filed for regulatory approval in September 2025.

(b)RFP is seeking up to 4,000 MWs (cumulatively) from intermittent (wind, solar), non-intermittent (dispatchable) and emerging technology resources. Five wind resources selected from the 2024 RFP have already been submitted and approved by the IURC totaling 574 MWs. I&M expects to file applications with the IURC for regulatory approval of additional resources from the 2024 RFP.

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

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

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

Capacity Purchase Agreements

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

Regulatory Matters - Utility Rates and Rate Proceedings

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

The following tables summarize the completed and pending base rate case proceedings. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

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

Pending Base Rate Case Proceedings

Other Significant Regulatory Matters

2025 West Virginia Securitization Filing

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

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

2025 Virginia Securitization Legislation and Securitization Filing

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

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

NOLCs in Transmission Formula Rates - June 2025 FERC Order

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

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

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

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

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

NOLCs in Retail Jurisdictions - IRS PLRs

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

(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.

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

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

(b)Awaiting receipt of jurisdiction specific IRS PLR.

(c)Pending in 2025 Arkansas Base Rate Case.

Beginning in the second quarter of 2024 and continuing until the NOLC revenue requirement is in rates, AEP is recognizing additional regulatory assets related to revenue requirement amounts to be collected from customers. As of September 30, 2025, AEP has NOLC regulatory assets of $118 million on its balance sheet.

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

In January 2025, AEP announced a partnership whereby nonaffiliated entities will acquire a 19.9% noncontrolling interest in OHTCo and IMTCo for $2.82 billion. The transaction closed in June 2025 and AEP received cash proceeds of approximately $2.78 billion, net of transaction costs. Net proceeds are being used to help finance AEP’s capital plan. See “Noncontrolling Interest in OHTCo and IMTCo” section of Note 6 for additional information.

Kentucky Securitization

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

Inflation, Tariffs on International Trade and Supply Chain Disruption

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

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

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

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

New Legislation

Ohio Legislation

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

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

Texas Legislation

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

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

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

Oklahoma Legislation

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

Federal Tax Legislation

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

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

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

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

Forward Sale of Equity

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

Valley Link Investment (Applies to AEP and Transource Energy)

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

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

Fuel Cell Agreement

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

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

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

LITIGATION

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

Claims for Indemnification Made by Owners of the Gavin Power Station

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

ENVIRONMENTAL ISSUES

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

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

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

Impact of Environmental Compliance on the Generating Fleet

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

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

Clean Air Act Requirements

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

National Ambient Air Quality Standards

The Federal EPA periodically reviews and revises the NAAQS for criteria pollutants under the CAA. Revisions tend to increase the stringency of the standards, which in turn may require AEP to make investments in pollution control equipment at existing generating units, or, since most units are already well controlled, to make changes in how units are dispatched and operated. In February 2024, the Federal EPA finalized a new more stringent annual primary PM 2.5 standard.

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

Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR) in 2005, which could require power plants and other facilities to install best available retrofit technology to address regional haze in federal parks and other protected areas. CAVR is implemented by the states, through SIPs, or by the Federal EPA, through FIPs. In 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs. Petitions for review of the final rule revisions were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In early 2018, the Federal EPA announced plans to revisit aspects of the final rule raised by petitioners in petitions for administrative reconsideration, and the court granted the Federal EPA’s motion to hold the litigation in abeyance. In September 2025, the Federal EPA issued an advanced notice of proposed rulemaking, soliciting information to assist the Federal EPA in potentially restructuring the Regional Haze Rule (RHR). Under the current RHR, states must submit SIPs to protect visibility in mandatory Class I Federal areas to demonstrate reasonable progress towards the national visibility goal. The Federal EPA intends to propose revisions to the RHR based on the input received.

The Federal EPA disapproved portions of the Texas regional haze SIP and finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOX regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO 2 emissions trading program based on CSAPR allowance allocations. Environmental groups filed challenges to these various rulemakings in district courts in the Fifth Circuit and the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and intervened in the Fifth Circuit litigation in support of the Federal EPA. In July 2024, the U.S. District Court for the District of Columbia Circuit entered a consent decree setting deadlines for the Federal EPA to rule on Regional Haze SIPs for 32 states, including Texas. In September 2024, the Federal EPA signed a proposed rule to partially approve and partially disapprove the Texas SIP revision. In May 2025, the Federal EPA proposed to withdraw the prior proposed rule, including the proposed partial disapproval of the Texas SIP revision, and instead has proposed to approve the Texas Regional Haze SIP. The Federal EPA has recently approved Regional Haze SIP submissions for Ohio and West Virginia, both of which have been appealed by environmental groups. Management will continue to monitor the litigation and cannot predict the outcome.

Cross-State Air Pollution Rule

CSAPR is a regional trading program that the Federal EPA began implementing in 2015 to address interstate transport of emissions that contribute significantly to nonattainment and interfere with maintenance of the 1997 ozone NAAQS and the 1997 and 2006 PM 2.5 NAAQS in downwind states. CSAPR relies on SO 2 and NOX allowances and individual state budgets to compel further emission reductions from electric utility generating units. Interstate trading of allowances is allowed on a restricted basis. The Federal EPA has revised, or updated, the CSAPR trading programs several times since they were established.

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

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

Climate Change, CO 2 Regulation and Energy Policy

In April 2024, the Administrator of the Federal EPA signed new GHG standards and guidelines for new and existing fossil-fuel fired sources. The rule relies on carbon capture and sequestration and natural gas co-firing as means to reduce CO 2 emissions from coal fired plants and carbon capture and sequestration or limited utilization to reduce CO 2 emissions from new gas turbines. The rule also offers early retirement of coal plants in lieu of carbon capture and storage as an alternative means of compliance.

The rule has been challenged by 27 states, numerous companies, trade associations and others. AEP has joined with several other utilities to challenge the rule and has asked the court to stay the rule during the litigation, and the appeals have been consolidated. In July 2024, the U.S. Court of Appeals for the District of Columbia Circuit denied those motions to stay and several parties, including AEP and other utilities, filed applications with the United States Supreme Court seeking an emergency stay. The Supreme Court denied those applications in October 2024 and the challenges to the rule before the D.C. Circuit Court of Appeals were placed on an expedited schedule, with oral arguments held in December 2024. On February 5, 2025, the Federal EPA filed an unopposed motion asking the court to withhold issuing an opinion and to hold the case in abeyance for 60 days to allow the new Agency leadership to review the underlying rule. The court granted that motion on February 19, 2025 and ordered the parties to file motions to govern further proceedings by April 21, 2025. On April 21, 2025, the Federal EPA filed an unopposed motion to hold the case in abeyance while the Federal EPA conducts a rulemaking to reassess the challenged rule, with status reports due every 90 days. The court has not ruled on that motion. On June 11, 2025, the Federal EPA proposed to determine that GHG emissions from fossil-fueled power plants do not significantly contribute to air pollution that may endanger public health or the environment. This determination would eliminate all GHG standards for existing and new fossil-fuel plants. As an alternative, the Federal EPA proposed to eliminate GHG standards for existing coal and gas units and to keep only certain emission limits applicable to new sources. These proposals have not been finalized. On July 29, 2025, the Federal EPA announced that it would be proposing a repeal of the 2009 Endangerment Finding, which determined that greenhouse gas emissions endanger public health and welfare. The 2009 Endangerment Finding is the basis of Federal EPA’s authority to regulate greenhouse gas emissions under the Clean Air Act and was used to first regulate motor vehicle emissions. Management is evaluating the Federal EPA’s proposed repeal of the 2009 Endangerment Finding and its impact on Federal EPA’s authority to regulate greenhouse gas emissions from electric generators. Management cannot predict the outcome of the current litigation or Federal EPA’s proposed actions related to the rule or the Endangerment Finding and any subsequent litigation that may result. Excessive costs to comply with environmental regulations have led to the announcement of early plant closures across the country. The Federal EPA’s 2024 GHG rules, and suite of other new rules issued simultaneously and discussed below, are directed at the fossil-fuel fired electric utility industry and could force AEP to close additional coal-fired generation facilities earlier than their estimated useful life, if those rules remain in place. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.

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

MATS Rule

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

CCR Rule

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

Clean Water Act Regulations

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

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

In September 2025, the Federal EPA proposed to extend the compliance deadlines in the 2024 ELG Rule by five years as well as to establish a site-specific mechanism for extending compliance deadlines for both the 2020 and 2024 ELG Rules. The Federal EPA also published a direct final rule extending to December 31, 2031, the 2024 ELG Rule deadline for submitting a NOPP electing to cease coal combustion by December 31, 2034. The direct final rule extending the NOPP deadline becomes effective on December 1, 2025, if no adverse comments are received; otherwise, the proposed NOPP extension must complete the notice and comment process initiated by the proposed rule before taking effect. The Federal EPA is also soliciting comments on zero liquid discharge technology to be used in a future rulemaking. Management cannot predict the outcome of any further actions by the Federal EPA related to the ELG rule.

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

Impact of Environmental Regulation on Coal-Fired Generation

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

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

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

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

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

(d)Represents Arkansas, Texas and FERC jurisdictional share.

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

(f)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028. In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively.

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

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

AEP’s Reportable Segments

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

•Vertically Integrated Utilities

•Transmission and Distribution Utilities

•AEP Transmission Holdco

•Generation & Marketing

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

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

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

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

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

Heating Degree Days and Cooling Degree Days

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

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

VERTICALLY INTEGRATED UTILITIES

Summary of KWh Energy Sales for Vertically Integrated Utilities

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities

•Retail Revenues increased $212 million primarily due to the following:

•A $140 million increase in rider revenues.

•A $64 million increase in weather-normalized revenues primarily in the residential and commercial classes, partially offset by a decrease in the industrial class.

•A $42 million increase in base rate revenues at I&M and PSO.

•A $35 million increase in fuel revenues primarily due to increases at APCo and I&M, partially offset by a decrease at PSO.

•A $39 million decrease due to regulatory provisions for refund at I&M.

•A $22 million decrease in weather-related usage primarily in the residential class driven by an 8% decrease in cooling degree days.

•A $10 million decrease in rider revenues at APCo.

•Off-system Sales increased $30 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales at I&M.

•Transmission Revenues increased $23 million primarily due to continued transmission investment.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $68 million primarily due to increases at APCo, I&M and PSO, partially offset by a decrease at SWEPCo.

•Other Operation and Maintenance expenses increased $117 million primarily due to the following:

•A $34 million increase in distribution expenses primarily due to vegetation management costs.

•An $18 million increase in employee-related expenses.

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

•A $10 million increase in generation expenses at PSO primarily due to acquisitions of generation facilities in 2025.

•A $9 million increase in transmission vegetation management costs.

•A $7 million increase in nuclear expenses at Cook Plant.

•Depreciation and Amortization expenses increased $17 million primarily due to the amortization of the Storm Recovery Funding securitized assets at SWEPCo and an overall higher depreciable base across all companies.

•Allowance for Equity Funds Used During Construction increased $7 million primarily due to higher CWIP.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $9 million primarily due to an increase in discount rates from 2024 to 2025.

•Interest Expense increased $29 million primarily due to higher long-term debt balances at PSO, an increase primarily associated with Storm Recovery Funding securitization bonds at SWEPCo and an increase at KPCo due to issuing securitization bonds in June 2025.

•Income Tax Benefit decreased $39 million primarily due to the following:

•A $14 million decrease due to an increase in flow-through cost of removal.

•A $10 million decrease due to an increase in pretax book income.

•An $8 million decrease due to the timing of the recognition of PTCs.

•A $7 million decrease due to an increase in flow-through CAMT expense.

•Retail Revenues increased $669 million primarily due to the following:

•A $240 million increase in rider revenues across all companies.

•A $173 million increase in base rate revenues at I&M and PSO.

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

•A $95 million increase in fuel revenues primarily due to increases at APCo and I&M, partially offset by a decrease at PSO.

•A $92 million increase in weather-normalized revenues primarily in the residential and commercial classes, partially offset by a decrease in the industrial class.

•An $18 million increase in weather-related usage primarily in the residential class driven by a 32% increase in heating degree days.

•A $110 million decrease due to regulatory provisions for refund at I&M.

•Off-system Sales increased $92 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales at I&M.

•Transmission Revenues increased $95 million primarily due to the following:

•A $56 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $39 million increase due to continued transmission investment.

•Other Revenues increased $13 million primarily due to an increasein sales of renewable energy credits at APCo.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $194 million primarily due to increases at APCo and I&M, partially offset by decreases at PSO and SWEPCo.

•Other Operation and Maintenance expenses increased $143 million primarily due to the following:

•A $100 million increase in PJM and SPP transmission expenses.

•A $56 million increase in distribution expenses primarily due to vegetation management costs.

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

•An $18 million increase at APCo due to recoverable energy assistance program expenses for qualified Virginia customers.

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

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

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

•Depreciation and Amortization expenses increased $124 million primarily due to the following:

•A $77 million increase primarily due to a higher depreciable base at APCo, I&M and SWEPCo.

•A $17 million increase at SWEPCo due to the amortization of the Storm Recovery Funding securitized assets.

•A $16 million increase due to a prior year deferral combined with current year amortization of Excess ADIT as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking at I&M.

•Taxes Other Than Income Taxes decreased $13 million primarily due to lower business and occupation taxes at APCo and WPCo.

•Allowance for Equity Funds Used During Construction increased $14 million primarily due to higher CWIP.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $21 million primarily due to an increase in discount rates from 2024 to 2025.

•Interest Expense increased $84 million primarily due to the following:

•A $37 million increase due to a prior year deferral of expenses as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking at I&M, PSO and SWEPCo.

•A $26 million increase due to higher long-term debt balances at PSO.

•A $17 million increase associated with Storm Recovery Funding securitization bonds at SWEPCo.

•Income Tax Benefit decreased $207 million primarily due to the following:

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

•A $67 million decrease due to an increase in pretax book income.

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

•A $21 million decrease due to a decrease in amortization of Excess ADIT.

•A $114 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

TRANSMISSION AND DISTRIBUTION UTILITIES

Summary of KWh Energy Sales for Transmission and Distribution Utilities

(a)Represents energy delivered to distribution customers.

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

Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities

•Retail Revenues increased $87 million primarily due to the following:

•A $49 million increase due to higher prices for purchased power for OPCo’s SSO customers.

•A $31 million increase in base case and rider revenues.

•A $12 million increase in weather-normalized revenues primarily in the residential class.

•A $9 million decrease in weather-related usage primarily driven by a 13% decrease in cooling degree days in Ohio.

•Off-system Sales increased$16 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.

•Transmission Revenues increased $18 million primarily due to the following:

•A $28 million increase in interim rates driven by increased transmission investments in Texas.

•A $14 million decrease due to lower peak loads included in the 2025 billing rates in Texas.

•Other Revenues decreased $7 million primarily due to the following:

•A $12 million decrease primarily due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

•A $5 million increase primarily due to data center load study revenues in Ohio.

•Purchased Electricity for Resale expenses increased $46 million primarily due to the following:

•A $39 million increase in recoverable auction purchases in Ohio primarily due to higher prices.

•A $6 million increase in recoverable alternative energy rider expenses in Ohio.

•Other Operation and Maintenance expenses increased $24 million primarily due to the following:

•A $15 million increase in recoverable transmission expenses in Texas.

•A $4 million increase in distribution expenses in Texas.

•Depreciation and Amortization expenses decreased $3 million primarily due tothe following:

•A $19 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

•A $6 million decrease due to the deferral of eligible costs related to the UTM.

•An $11 million increase primarily due to higher depreciable base and lower capital rider under recoveries in Ohio.

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

•Taxes Other Than Income Taxes increased$9 million primarily due to an increase in property taxes in Ohio.

•Income Tax Expense increased $8 million primarily due to an increase in pretax book income.

•Retail Revenues increased $151 million primarily due to the following:

•A $164 million increase in base case and rider revenues.

•A $25 million increase in weather-related usage driven by a 32% increase in heating degree days in the Eastern Region and an 83% increase in heating degree days in the Western Region.

•A $39 million decrease due to lower purchased power in OPCo’s SSO customers.

•Off-system Sales increased $42 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.

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

•A $70 million increase in interim rates driven by increased transmission investments in Texas.

•An $11 million increase primarily due to continued transmission investment in Ohio.

•A $48 million decrease due to lower peak loads included in the 2025 billing rates in Texas.

•Other Revenues decreased $61 million primarily due to the following:

•A $54 million decrease primarily due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

•A $7 million decrease primarily due to lower third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

•Purchased Electricity for Resale expenses increased $38 million primarily due to the following:

•A $24 million increase primarily due to the amortization of OVEC-related purchased power regulatory assets driven by higher market prices.

•A $24 million increase due to a reduction in regulatory assets for OVEC-related purchased power costs that are no longer probable of future recovery due to approved legislation in Ohio in 2025.

•A $6 million decrease in recoverable alternative energy rider expenses.

•Purchased Electricity from AEP Affiliates expenses decreased $37 million primarily due to decreased recoverable purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $103 million primarily due to the following:

•A $120 million increase in recoverable transmission expenses.

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

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

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

•A $20 million decrease related to recoverable energy assistance program expenses for qualified Ohio customers.

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

•Depreciation and Amortization expenses decreased $48 million due to the following:

•A $51 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds in December 2024.

•A $17 million decrease due to the deferral of eligible costs related to the UTM.

•A $9 million decrease primarily due to capital rider under-recoveries in Ohio.

•A $28 million increase due to a higher depreciable base in Texas.

•Other Income decreased$5 million primarily due to lower interest income as a result of lower advances to affiliates.

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

•Interest Expense increased $20 million primarily due to:

•A $32 million increase due to higher debt balances in Ohio and higher debt balances and interest rates in Texas.

•A $5 million increase due to a decrease in the debt component of AFUDC in Texas.

•A $19 million decrease due to the deferral of eligible costs related to the UTM.

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

AEP TRANSMISSION HOLDCO

Summary of Investment in Transmission Assets for AEP Transmission Holdco

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

•Transmission Revenues increased $61 million primarily due to continued transmission investment.

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

•Other Operation and Maintenance expenses increased $13 million primarily due to an increase in employee-related expenses, vegetation management expenses and other miscellaneous expenses.

•Depreciation and Amortization expenses increased $13 million primarily due to a higher depreciable base.

•Taxes other than Income Taxes increased $6 million due to higher property taxes driven by increased investment.

•Interest Expense increased $7 million primarily due to higher long-term debt balances and interest rates.

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

•Transmission Revenues increased $372 million primarily due to the following:

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

•A $158 million increase due to continued transmission investment.

Expenses and Other, Income Tax Expense, Equity Earnings of Unconsolidated Subsidiaries and Net Income Attributable to Noncontrolling Interests changed between years as follows:

•Other Operation and Maintenance expenses increased $13 million primarily due to an increase in vegetation management expenses, affiliated rent expense and other miscellaneous expenses, partially offset by a decrease in employee-related expenses primarily due to the voluntary severance program that occurred in the second quarter of 2024.

•Depreciation and Amortization expenses increased $33 million due to a higher depreciable base.

•Taxes other than Income Taxes increased $7 million primarily due to higher property taxes driven by increased investment.

•Interest and Investment income decreased by $7 million due to lower advances to affiliates.

•Interest Expense increased $13 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense decreased $183 million primarily due to the following:

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

•A $62 million increase due to an increase in pretax book income.

•Equity Earnings of Unconsolidated Subsidiaries decreased $6 million due to lower pretax earnings by ETT and PATH-WV.

•Net Income Attributable to Noncontrolling Interests increased $87 million primarily due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.

GENERATION & MARKETING

•Merchant Generation increased $27 million primarily due to higher realized prices in 2025.

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

•Retail, Trading and Marketing increased $195 million primarily due to higher MTM hedging activity and higher market prices in 2025.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $211 million primarily due to an increase in energy costs in 2025.

•Other Operation and Maintenance expenses increased $15 million primarily due to the gain on a solar contract termination agreement in 2024.

•Income Tax Expense increased $39 million primarily due to a decrease in amortization of deferred ITCs related to the sale of AEP OnSite Partners in September 2024.

•Merchant Generation increased $67 million primarily due to higher realized prices in 2025.

•Renewable Generation decreased $25 million primarily due to the sale of AEP OnSite Partners in September 2024.

•Retail, Trading and Marketing increased $454 million primarily due to higher MTM hedging activity and higher market prices in 2025.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $550 million primarily due to an increase in energy costs in 2025.

•Other Operation and Maintenance expenses decreased $29 million primarily due to renewable contract termination proceeds in 2025 and the sale of AEP OnSite Partners in September 2024.

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

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

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

•Interest Expense decreased $10 million due to lower advances from affiliates.

•Income Tax Expense increased $74 million primarily due to:

•A $54 million increase due to a decrease in amortization of deferred ITCs related to the sale of NMRD and AEP OnSite Partners in 2024.

•A $12 million increase due to an increase in pretax book income.

CORPORATE AND OTHER

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

•A $28 million decrease in interest expense due to lower interest rates.

•A $23 million increase at EIS primarily due to decreased insurance reserves.

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

•A $6 million increase in equity earnings.

These increases in earnings were partially offset by:

•A $15 million increase in Income Tax Expense primarily due to an increase in pretax book income.

•A $13 million decrease in interest income primarily due to lower advances to affiliates.

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

•A $41 million decrease in interest expense due to lower interest rates.

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

•An $18 million increase in equity earnings.

•A $14 million increase in Income Tax Benefit primarily due to an increase in PTCs.

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

These increases in earnings were partially offset by:

•A $29 million decrease in interest income primarily due to lower advances to affiliates.

AEP CONSOLIDATED INCOME TAXES

Income Tax Expense increased $101 million primarily due to:

•A $38 million increase due to a decrease in amortization of deferred ITCs related to the sale of AEP OnSite Partners in 2024.

•A $26 million increase due to an increase in pretax book income.

•A $13 million increase due to an increase in flow-through expense primarily driven by cost of removal.

•A $10 million increase due to a decrease in PTCs.

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

•A $7 million increase due to an increase in flow-through CAMT expense.

Income Tax Benefit decreased $111 million primarily due to:

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

•A $184 million decrease due to an increase in pretax book income.

•A $54 million decrease due to a decrease in amortization of deferred ITCs related to the sale of NMRD and AEP OnSite Partners in 2024.

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

•A $16 million decrease due to a decrease in amortization of Excess ADIT.

•A $13 million decrease due to an increase in flow-through expense primarily driven by cost of removal.

These decreases in Income Tax Benefit were partially offset by:

•A $368 million increase due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $37 million increase due to an increase in PTCs.

FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

AEP’s ratio of debt-to-total capital decreased from 62.6% to 60.0% as of December 31, 2024 and September 30, 2025, respectively, primarily due to an increase in earnings and the Midwest Transmission Holdings Noncontrolling Interest transaction, partially offset by an increase in long-term debt to support AEP’s capital investment plan in addition to working capital needs.

Liquidity

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

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

Net Available Liquidity

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

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

Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2025 was $364 million with maturities ranging from October 2025 to September 2026.

Securitized Accounts Receivables

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

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements. Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of September 30, 2025, this contractually-defined percentage was 55.5%. Non-performance under these covenants could result in an event of default under these credit agreements. In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $100 million, would cause an event of default under these credit agreements. This condition also applies, at the more restrictive level of $50 million of debt outstanding, in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable. However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

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

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

March 2025 Forward Sale of Equity

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

ATM Program

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

Dividend Policy and Restrictions

The Board of Directors of AEP (AEP Board) declared a quarterly dividend of $0.95 per share in October 2025. Future dividends are at the discretion of the AEP Board and may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 13 for additional information.

Credit Ratings

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

CASH FLOW

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

Operating Activities

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

Net Cash Flows from Operating Activities increased by $54 million primarily due to the following:

•A $757 million increase in cash from Net Income, after non-cash adjustments. See “Results of Operations” for further detail.

This increase in cash was partially offset by:

•A $476 million decrease in cash from Change in Other Noncurrent Assets primarily due to timing differences in collections from customers under rate rider mechanisms, including storm restoration expenses incurred in several jurisdictions. See Note 4 - Rate Matters for additional information.

•A $140 million decrease in cash primarily due to the timing of fuel and purchase power related revenues and expenses.

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

Investing Activities

Net Cash Flows Used for Investing Activities increased by $3 billion primarily due to the following:

•A $1.7 billion increase due to the acquisitions of Green Country Power Plant, Pixley Solar Energy Facility, Flat Ridge IV Wind Energy Facility and Flat Ridge V Wind Energy Facility. See “Acquisitions” section of Note 6 for additional information.

•An $833 million increase in Construction Expenditures primarily due to increases in Vertically Integrated Utilities of $409 million and Transmission and Distribution Utilities of $348 million.

•A $352 million decrease in Proceeds from Sales of Assets primarily due to the sale of AEP OnSite Partners in 2024. See “Dispositions” section of Note 6 for additional information.

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

Financing Activities

Net Cash Flows from (Used for) Financing Activities increased by $3.9 billion primarily due to the following:

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

•A $2.5 billion increase in issuances of long-term debt. See Note 13 - Financing Activities for additional information.

These increases in cash were partially offset by:

•An $835 million increase in retirements of long-term debt. See Note 13 - Financing Activities for additional information.

•A $326 million decrease in issuances of common stock primarily under AEP’s ATM Program. See Note 13 - Financing Activities for additional information.

See the “Long-term Debt Subsequent Events” section of Note 13 for Long-term debt and other securities issued, retired and principal payments made after September 30, 2025 through October 29, 2025, the date that the third quarter Form 10-Q was filed.

BUDGETED CAPITAL EXPENDITURES

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

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

The 2026-2030 estimated capital expenditures by Business Segment are as follows:

SIGNIFICANT CASH REQUIREMENTS

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

ACCOUNTING STANDARDS

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