ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AEP The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations. Year-to-year comparisons between 2024 and 2023 have been omitted from this Form 10-K but may be found in "Management's Discussion and Analysis of Financial Condition" in Part II, Item 7 of AEP’s Form 10-K for the fiscal year ended December 31, 2024. AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo Omitted pursuant to Instruction I(2)(a).  Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations. ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo The information required by this item is incorporated herein by reference to the material under the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations. ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 39 2025 Annual Reports American Electric Power Company, Inc. and Subsidiary Companies AEP Texas Inc. and Subsidiaries AEP Transmission Company, LLC and Subsidiaries Appalachian Power Company and Subsidiaries Indiana Michigan Power Company and Subsidiaries Ohio Power Company and Subsidiaries Public Service Company of Oklahoma Southwestern Electric Power Company Consolidated Audited Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations 40 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES INDEX OF ANNUAL REPORTS Page Number American Electric Power Company, Inc. and Subsidiary Companies: Management’s Discussion and Analysis of Financial Condition and Results of Operations 42 Report of Independent Registered Public Accounting Firm (PCAOB ID 238 ) 92 Management’s Report on Internal Control Over Financial Reporting 95 Consolidated Financial Statements 96 AEP Texas Inc. and Subsidiaries: Management’s Narrative Discussion and Analysis of Results of Operations 102 Report of Independent Registered Public Accounting Firm (PCAOB ID 238 ) 104 Management’s Report on Internal Control Over Financial Reporting 106 Consolidated Financial Statements 107 AEP Transmission Company, LLC and Subsidiaries: Management’s Narrative Discussion and Analysis of Results of Operations 113 Report of Independent Registered Public Accounting Firm (PCAOB ID 238 ) 115 Management’s Report on Internal Control Over Financial Reporting 117 Consolidated Financial Statements 118 Appalachian Power Company and Subsidiaries: Management’s Narrative Discussion and Analysis of Results of Operations 123 Report of Independent Registered Public Accounting Firm (PCAOB ID 238 ) 126 Management’s Report on Internal Control Over Financial Reporting 128 Consolidated Financial Statements 129 Indiana Michigan Power Company and Subsidiaries: Management’s Narrative Discussion and Analysis of Results of Operations 135 Report of Independent Registered Public Accounting Firm (PCAOB ID 238 ) 138 Management’s Report on Internal Control Over Financial Reporting 140 Consolidated Financial Statements 141 Ohio Power Company and Subsidiaries: Management’s Narrative Discussion and Analysis of Results of Operations 147 Report of Independent Registered Public Accounting Firm (PCAOB ID 238 ) 150 Management’s Report on Internal Control Over Financial Reporting 152 Consolidated Financial Statements 153 Public Service Company of Oklahoma: Management’s Narrative Discussion and Analysis of Results of Operations 158 Report of Independent Registered Public Accounting Firm (PCAOB ID 238 ) 161 Management’s Report on Internal Control Over Financial Reporting 163 Financial Statements 164 Southwestern Electric Power Company Consolidated: Management’s Narrative Discussion and Analysis of Results of Operations 170 Report of Independent Registered Public Accounting Firm (PCAOB ID 238 ) 173 Management’s Report on Internal Control Over Financial Reporting 175 Consolidated Financial Statements 176 Index of Notes to Financial Statements of Registrant s 182 41 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS EXECUTIVE OVERVIEW Company Overview AEP is one of the largest investor-owned electric public utility holding companies in the United States.  AEP’s electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. AEP’s subsidiaries operate an extensive portfolio of assets including: • Approximately 252,000 circuit miles of distribution lines. • Approximately 38,000 circuit miles of transmission lines, including approximately 2,000 circuit   miles of 765 kV lines. • Approximately 25,000 MWs of regulated owned generating capacity as of December 31, 2025. AEP is committed to executing its strategy to improve customers’ lives with reliable, affordable power. AEP’s mission is to put the customer first and is focused on six core principles: • Customer Service - Industry-best customer experience. • Employee Commitment - Safe and secure workplace; engaged, trained and developed employees. • Environmental Respect - Creative sustainable energy solutions. • Regulatory & Legislative Integrity - Balanced regulatory outcomes; Trusted industry leadership. • Operational Excellence - World-class asset performance. • Financial Strength - Strong financial discipline. 42 AEP CONSOLIDATED RESULTS OF OPERATIONS 2025 Compared to 2024 Earnings Attributable to AEP Common Shareholders increased from $3.0 billion in 2024 to $3.6 billion in 2025 primarily due to: • Investment in transmission assets, which resulted in higher revenues and income. • The favorable impact from the receipt of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates. • A revenue refund provision recorded in 2024 associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case. • A decrease in operating expense due to the Federal EPA’s revised CCR rule which resulted in higher operating expenses in 2024. • A decrease in operating expenses due to the voluntary severance program that occurred in the second quarter of 2024. • An increase in sales volumes driven by favorable weather. • Favorable rate proceedings in AEP’s various jurisdictions. These increases were partially offset by: • The favorable impact from the receipt of PLRs in 2024 related to the treatment of NOLCs in retail ratemaking. See “NOLCs in Retail Jurisdictions - IRS PLRs” section below for additional information. • An increase in operating expenses recorded in 2025 due to an impairment of in-process internal use software development costs. See “Results of Operations” section for additional information by operating segment. 43 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 items are not indicative of AEP's ongoing performance. This information is intended to enhance an investor’s overall understanding of period over period financial results and provide an indication of AEP’s baseline operating performance by excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. These non-GAAP financial measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations. Reconciliation of Reported GAAP Earnings to Operating Earnings The following table presents a reconciliation of operating earnings to the most directly comparable GAAP measure. Year Ended December 31, 2025 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Reported GAAP Earnings $ 3,580  $ 488  $ 1,075  $ 457  $ 414  $ 328  $ 252  $ 388 Adjustments to Reported GAAP Earnings (a): Mark-to-Market Impact of Commodity Hedging Activities (b) 9  —  —  —  7  —  —  — Sale of AEP OnSite Partners (c) 10  —  —  —  —  —  —  — Impact of Ohio Legislation (d) 19  —  —  —  —  19  —  — FERC NOLC Order (e) (480) —  (354) (29) (36) —  (4) (54) Impairment of Software Development Costs (f) 52  11  —  9  7  14  5  4 Total Specified Items (390) 11  (354) (20) (22) 33  1  (50) Operating Earnings $ 3,190  $ 499  $ 721  $ 437  $ 392  $ 361  $ 253  $ 338 (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 an impairment of in-process internal use software development costs. 44 Year Ended December 31, 2024 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Reported GAAP Earnings $ 2,967  $ 420  $ 688  $ 422  $ 391  $ 306  $ 249  $ 321 Adjustments to Reported GAAP Earnings (a): Mark-to-Market Impact of Commodity Hedging Activities (b) (85) —  —  —  19  —  —  — Remeasurement of Excess ADIT Regulatory Liability (c) (45) —  —  —  (12) —  —  (33) Impact of NOLC on Retail Ratemaking (d) (260) —  —  —  (69) —  (57) (134) Disallowance - Dolet Hills Power Station (e) 11  —  —  —  —  —  —  11 Provision for Refund - Turk Plant (f) 117  —  —  —  —  —  —  117 Sale of AEP OnSite Partners (g) 11  —  —  —  —  —  —  —  — Severance and Pension Settlement Charges (h) 121  16  9  20  17  19  8  23 Federal EPA CCR Rule (i) 111  —  —  —  11  41  —  — SEC Matter Loss Contingency (j) 19  —  —  —  —  —  —  — State Tax Law Changes (k) 11  —  —  —  —  —  —  11 Total Specified Items 11  16  9  20  (34) 60  (49) (5) Operating Earnings $ 2,978  $ 436  $ 697  $ 442  $ 357  $ 366  $ 200  $ 316 (a) Excluding tax related adjustments, all items presented in the table are tax adjusted at the statutory rate unless otherwise noted. (b) Represents the impact of mark-to-market economic hedging activities. (c) Represents the impact of the remeasurement of Excess ADIT in Arkansas and Michigan 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. (d) 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. (e) Represents the impact of a disallowance recorded at SWEPCo on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024. (f) Represents a provision for revenue refunds on certain capitalized costs associated with the Turk Plant. (g) Represents the loss on the sale of AEP OnSite Partners. (h) Represents employee severance charges and pension settlement expenses. (i) Represents the impact of the Federal EPA Revised CCR Rule. (j) Represents an estimated loss contingency related to a previously disclosed SEC investigation. (k) Represents the impact of the remeasurement of ADIT as a result of enacted state tax legislation in Arkansas and Louisiana. 45 Year Ended December 31, 2023 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Reported GAAP Earnings $ 2,208  $ 370  $ 614  $ 294  $ 336  $ 328  $ 209  $ 220 Adjustments to Reported GAAP Earnings (a): Mark-to-Market Impact of Commodity Hedging Activities (b) 228  —  —  —  (20) —  —  — Remeasurement of Excess ADIT Regulatory Liability (c) (46) —  —  (46) —  —  —  — ENEC Fuel Disallowance (d) 181  —  —  101  —  —  —  — Turk Impairment (e) 80  —  —  —  —  —  —  80 Sale of Unregulated Renewables (f) 73  —  —  —  —  —  —  — Kentucky Operations (g) (34) —  —  —  —  —  —  — Change in Texas Legislation (h) (24) (20) —  —  —  —  —  (4) FERC NOLC Disallowance (i) 24  —  36  (4) (2) (9) (3) 1 Severance Charges (j) 19  3  1  4  3  5  1  2 Impairment of Investment in NMRD (k) 15  —  —  —  —  —  —  — Total Specified Items 516  (17) 37  55  (19) (4) (2) 79 Operating Earnings $ 2,724  $ 353  $ 651  $ 349  $ 317  $ 324  $ 207  $ 299 (a) Excluding tax related adjustments, all items presented in the table are tax adjusted at the statutory rate unless otherwise noted. (b) Represents the impact of mark-to-market economic hedging activities. (c) Represents the impact of the remeasurement of ADIT - NOLC in Virginia and West Virginia. (d) Represents the impact of the disallowance of the recovery of certain deferred fuel costs in West Virginia. (e) Represents the impact of the disallowance of certain capitalized costs associated with the Turk Plant. (f) Represents the loss on the sale of the Competitive Contracted Renewable Portfolio and other related third-party transaction costs. (g) Represents an adjustment to the loss on the expected sale of the Kentucky Operations which was terminated in April 2023 and other related third-party transaction costs. (h) Represents the impact of recent legislation in Texas regarding recovery of certain employee incentives. (i) Represents the impact of the FERC decision denying stand-alone treatment of NOLCs for transmission formula rates. (j) Represents the impact of AEP's workforce reduction in 2023. (k) Represents the impairment of AEP's investment in the NMRD joint venture. 46 ELECTRIC INDUSTRY TRANSFORMATION The electric utility industry is undergoing a historic transformation, fueled by rapid commercial customer class load growth, especially from data processing and other energy-intensive operations, as well as shifting regulator and customer expectations, evolving public policies, rising stakeholder demands, demographic changes, new competitive pressures, emerging technologies, necessary reliability investments and volatile commodity markets. AEP projects growth in the system peak demand by 2030 across its diversified service territory, with especially strong projected growth in Indiana, Ohio, Oklahoma and Texas. To meet this accelerating demand, AEP outlined a $72 billion, five year capital plan focused on strengthening transmission infrastructure, adding new generation resources to serve both existing customers and large forecasted load additions and continuing to enhance distribution system reliability. Throughout this investment cycle, AEP remains committed to focusing on customer affordability. AEP expects to utilize various levers to address affordability including incremental load growth, rate design, continued operation and maintenance expense efficiency and financing mechanisms such as securitizations. AEP has advanced large-load tariff proposals and tariff modifications aimed at enabling the rapid interconnection of committed large load customers while protecting existing customers from increased costs. These proposals have been filed in eight of AEP’s jurisdictions, with four already approved by state commissions. AEP is actively engaging with regulators, policymakers, RTOs, customers and suppliers to advance system reliability, resiliency and affordability across its service territories during this period of rapid transformation. Additionally, AEP continues to secure resources to support forecasted load requirements in its regulated jurisdictions including: • The addition of 2.2 GWs of owned generating capacity in 2025. • Securing additional turbines for gas-fired turbine capacity. • RFPs seeking approximately 12,700 MWs of generating capacity. • Capacity purchase agreements to satisfy capacity reserve margins to serve customers. • Long-term transmission construction partnership with a major U.S.-based infrastructure services company. Customer Demand AEP uses sales volumes by customer class as a way to measure drivers of customer demand. In 2025, AEP experienced an increase in customer demand for power driven primarily by new data processing loads coming online in 2025 in the commercial customer class and favorable weather and marginal growth in the residential class. The table below shows the percentage change in sales volume by customer class. (a) Percentage change for the year ended December 31, 2025 as compared to the year ended December 31, 2024. Load figures are billed retail sales excluding firm wholesale load. 47 Large Load/Data Center Tariffs Several AEP utility subsidiaries have made rate filings with state commissions to establish new tariffs for data centers and other large load customers. The new tariffs are designed to protect existing customers by strengthening and lengthening contract terms with large customers. These new protections include contract lengths of up to 20 years and take-or-pay contractual minimums which can require a customer to pay for as much as 90% of their contracted demand. In practice, these provisions reduce risks around the build out of large load infrastructure on existing customers, promoting stability and affordability. The table below provides a summary of the status of these new data center and large load tariffs. Company Jurisdiction Large Load Tariff Status (a) Customer Eligibility APCo Virginia Large Power Service Pending New load of 150 MWs or more/100 MWs for individual site APCo West Virginia Large Capacity/Industrial Power Approved New load of 150 MWs or more/100 MWs for individual site I&M Indiana Industrial Power Approved New load of 150 MWs or more/70 MWs for individual site I&M Michigan Large Load Pending New load of 50 MWs or more KPCo Kentucky Industrial General Service Approved New commercial or industrial load of 150 MWs or more OPCo Ohio Data Center Approved New data center load of 25 MWs or more PSO Oklahoma Large Power and Light Pending New load of 75 MWs or more SWEPCo Texas Electric Service Large Load Pending New load of 75 MWs or more (a) Both the pending and the approved tariffs include certain requirements for cash, or cash related instruments, as deposits. In June 2025, Texas Senate Bill 6 (SB 6) became effective and was signed into law by the Governor of Texas. SB 6 establishes a standardized process 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. The PUCT is currently drafting rules through multiple active dockets related to large load interconnection standards, net-metering arrangements for co-location, large load forecasting criteria, large load reliability/demand reduction and transmission cost allocation review to implement SB 6. The rulemaking projects are on various timelines, with final adoptions planned throughout 2026. AEP Texas has signed Letters of Agreement for an incremental 36 gigawatts of load by 2030. As the PUCT finalizes its SB 6 rulemaking efforts, AEP Texas expects improved clarity and certainty around the timing and the amount of additional load connection in ERCOT. PJM Capacity Market Reform The AEP East Companies are members of PJM. Utilities in PJM can meet their capacity obligations by either: (a) participating in capacity auctions administered by PJM, or (b) via the Fixed Resource Requirement alternative (FRR) in which load-serving entities self-supply their generation through owned or contracted resources. All AEP East Companies other than AEP Ohio utilize the FRR alternative. In January 2026, the White House, all thirteen state governors from across the PJM footprint, and senior federal energy officials jointly released a Statement of Principles. This Statement of Principles is designed to increase capacity available in the PJM market for large load customers and to ensure the costs of those resources are paid for by the large load customers to protect existing customer affordability. The Statement of Principles directs PJM to hold a one-time Reliability Backstop Auction, accelerate capacity market reforms in response to unprecedented data center load growth, and align costs associated with new capacity coming into the market with the large load customers necessitating the resources. Subsequently, in a proceeding pending since 2025, the Board of Directors of PJM issued a decision letter initiating changes to PJM’s capacity market and interconnection processes. As direct participants in the PJM capacity market, these reforms have the potential to materially impact AEP’s competitive retail operations and could materially alter OPCo’s cost allocations to retail customers. 48 AEP will continue to engage constructively with governors, regulators, PJM, and state and federal policymakers to support reforms that strengthen grid reliability, enable economic growth, and provide transparent, durable investment signals for utilities and investors. Management will continue to monitor activity within PJM and cannot predict the ultimate impact of these early-stage capacity market reform efforts or whether the FRR alternative will be impacted. If changes to PJM auction rules affect AEP’s existing or prospective customer contracts or generation development strategy, it could affect future results of operations. New Generation Resources The growth of AEP’s regulated generation portfolio reflects the company’s focus on meeting increasing customer demand for power while balancing cost and reliability. Acquired Generation Facilities During 2025, PSO acquired four power generation facilities to strengthen its portfolio and enhance reliability. Additionally, in the fourth quarter of 2025, APCo acquired the Top Hat Wind Facility and SWEPCo acquired the Wagon Wheel Wind Facility. These transactions reflect the company’s focus on securing necessary generation to meet future customer demand. See “Acquisitions” section of Note 7 for additional information. The table below summarizes these acquisitions: Company Plant Name Fuel Type Location Acquisition Date Net Maximum Capacity (in MWs) PSO Pixley Solar Barber County, KS May 2025 189 PSO Green Country Natural Gas Jenks, OK June 2025 904 PSO Flat Ridge IV Wind Kingman and Harper Counties, KS June 2025 135 PSO Flat Ridge V Wind Kingman and Harper Counties, KS August 2025 153 APCo Top Hat Wind Logan County, Illinois November 2025 204 SWEPCo Wagon Wheel Wind Multiple Counties, Oklahoma December 2025 598 Total 2,183 Pending 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 Plant. Regulatory proceedings in all three jurisdictions are underway. 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 December 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 and received approval in October 2025. 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. In November 2025, the IURC issued an order granting a CPCN to I&M for its acquisition of the Oregon facility. I&M expects to close on the transaction in the first quarter of 2026. In January 2026, the IURC issued a separate order approving the settlement agreement in I&M’s Indiana Expedited Generation Resource (EGR) Plan filing. This order approving the settlement agreement allows I&M to seek expedited IURC approval of future proposed PPAs, capacity purchase agreements (CPAs) and owned generation resources to serve I&M’s increasing 49 customer load and to implement deferral accounting for the generation resources that are approved by the IURC through the EGR Plan process. 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 2028. Significant Approved Renewable Generation Filings AEP received regulatory approvals from various state regulatory commissions to acquire approximately 1,285 MWs of owned renewable generation facilities, totaling approximately $3.6 billion. The Financial Condition section below includes the estimated cost of these facilities in the Budgeted Capital Expenditures. In addition, AEP received regulatory approvals for 1,067 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 that are not yet in service as of December 31, 2025: Company Generation Type Expected Commercial Operation Owned/PPA Generating Capacity (in MWs) APCo Solar 2026-2027 PPA 113 APCo (a) Wind 2026-2029 Owned 401 I&M Solar 2026-2027 PPA 280 I&M Wind 2026-2030 PPA 674 I&M Solar 2028 Owned 469 PSO (b) Wind 2026 Owned 265 PSO (b) Solar 2027 Owned 150 Total Approved Renewable Projects 2,352 (a) APCo has one wind project under construction. (b) PSO has one wind project and one solar project under construction. Significant Generation Requests for Proposal (RFP) The table below includes active RFPs issued for both owned and purchased power generation. Projects selected will be subject to regulatory approval. Company Issuance Date Resource Type Projected In-Service Dates Generating Capacity (in MWs) PSO (a) November 2023 All-source 2027/2028 1,500 PSO January 2026 All-source 2029 4,000 I&M (b) September 2024 Wind, solar, dispatchable resources, BESS and emerging technology resources 2029 4,000 SWEPCo (c) January 2024 Wind, solar, BESS and natural gas resources 2027/2028 2,100 APCo May 2025 Owned wind, solar, co-located or stand-alone BESS 2029 800 APCo May 2025 Purchased power from wind, solar, hydro or geothermal 2029 300 Total Significant RFPs 12,700 (a) RFP was negotiated and filed for regulatory approval in September 2025. (b) Five wind resources selected totaling 574 MWs from the 2024 RFP have already been submitted and approved by the IURC. I&M expects to file applications with the IURC for regulatory approval of additional resources from the 2024 RFP in 2026. (c) Two self-build natural gas resources totaling 1,503 MWs were selected and filed for regulatory approval in December 2024. 50 Capacity Purchase Agreements In addition to the generation projects discussed above, AEP enters into Capacity Purchase Agreements (CPA) to satisfy operating companies’ capacity reserve margins to serve customers. The following table includes CPA amounts under contract as of December 31, 2025, by year, for the five-year period 2026-2030: I&M PSO SWEPCo Natural Gas Wind Natural Gas Wind Natural Gas Wind Delivery Start Year (in MWs) 2026 614  73  460  86  150  75 2027 769  —  410  86  300  100 2028 995  —  410  —  450  — 2029 995  —  410  —  450  — 2030 995  —  410  —  150  — 51 RECENT REGULATORY DEVELOPMENTS AND OTHER TRANSACTIONS Regulatory Matters - Utility Rates and Rate Proceedings The Registrants are involved in rate cases and other proceedings with their regulatory commissions in order to establish fair and appropriate electric service rates to recover their costs and earn a fair return on their investments.  Depending on the outcomes, these rate cases and proceedings can have a material impact on results of operations, cash flows and possibly financial condition. AEP is currently involved in the following key proceedings. The following tables show the Registrants’ completed and pending base rate case proceedings in 2025. See Note 4 - Rate Matters for additional information. Completed Base Rate Case Proceedings Annual Base Revenue Approved New Rates Company Jurisdiction Increase ROE Effective (in millions) APCo/WPCo West Virginia $ 76  9.25% August 2025 (a) SWEPCo Arkansas 85  9.65% February 2026 (a) The WVPSC approved recovery of the base rate increase through current ENEC rates. The WVPSC issued an interim order approving securitization of APCo and WPCo under-recovery balances, with activity subsequent to 2024 subject to a final prudence review prior to securitization. See the “2024 West Virginia Base Rate Case” and “2025 West Virginia Securitization Filing” sections of Note 4 for additional information. Pending Base Rate Case Proceedings Annual Filing Base Revenue Requested Company Jurisdiction Date Increase Request ROE (in millions) OPCo Ohio May 2025 $ 97  10.9% KPCo Kentucky August 2025 96  10.0% SWEPCo Texas October 2025 95  10.75% PSO Oklahoma January 2026 299  10.5% 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) $413 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 2026. 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. 52 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 apparent lack of significant benefit or cost savings for customers. In October 2025, the Hearing Examiner recommended the Virginia SCC approve the requested $1.4 billion for securitization. In November 2025, the Virginia SCC issued a financing order approving securitization of the requested $1.4 billion of Virginia jurisdictional costs. In accordance with Virginia statutory requirements and the financing order, the issuance of the securitization bonds is subject to final review by the Virginia SCC after bond pricing. APCo expects to proceed with the securitization bond issuance process and to complete the securitization process in the first half of 2026, subject to market conditions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. Company Increase (Decrease) in Pretax Income (a) Decrease in Income Tax Expense (b) Increase in Noncontrolling Interest (c) Increase in Net Income (in millions) APCo $ 8  $ 21  $ —  $ 29 I&M 17  28  —  45 PSO (13) 16  —  3 SWEPCo 17  39  —  56 AEPTCo 214  203  (55) 362 Other (d) (2) 6  —  4 AEP Total $ 241  $ 313  $ (55) $ 499 (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 Midwest Transmission Holdings” section of Note 7 for additional information. (d) Includes KGPCo, KPCo, OPCo and WPCo. 53 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 in the computation of Excess ADIT regulatory liabilities to be refunded to customers. Based on this conclusion, I&M, PSO and SWEPCo recognized regulatory assets related to revenue requirement amounts to be collected from customers, reduced Excess ADIT regulatory liabilities and recorded favorable impacts to net income in the first quarter of 2024 as shown in the table below: Company Increase in Pretax Income from the Recognition of Regulatory Assets Reduction in Income Tax Expense (a) Increase in Net Income (in millions) I&M $ 20  $ 50  $ 70 PSO 12  45  57 SWEPCo 35  101  136 AEP Total $ 67  $ 196  $ 263 (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. Company (a) Jurisdiction Status APCo Virginia Approved APCo/WPCo West Virginia (b) Pending I&M Indiana Approved I&M Michigan Approved KGPCo Tennessee Approved KPCo Kentucky (b) Pending PSO Oklahoma (b) Approved, subject to refund SWEPCo Arkansas (b) Pending SWEPCo Louisiana (b) Pending SWEPCo Texas Approved, subject to refund (a) AEP Texas and OPCo do not have NOLCs on a stand-alone basis. (b) Pending receipt of jurisdiction specific IRS PLR. 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 December 31, 2025, AEP has NOLC regulatory assets of $108 million on its balance sheet. Noncontrolling Interest in Midwest Transmission Holdings (Applies to AEP and AEPTCo) In June 2025, a nonaffiliated entity acquired a 19.9% noncontrolling interest in Midwest Transmission Holdings, a subsidiary of AEPTCo Parent that owns all of the issued and outstanding stock of OHTCo and IMTCo. AEP received cash proceeds of approximately $2.78 billion, net of transaction costs, which were used to help finance AEP’s capital plan. See “Noncontrolling Interest in Midwest Transmission Holdings” section of Note 7 for additional information. Kentucky Securitization Case 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. 54 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 became 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. In 2025, as a result of this legislation, 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. See “OVEC” section of Note 18 for additional information. 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 $56 million of eligible costs through December 2025 as a regulatory asset. 2025 UTM Filing 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, inclusive of the items outlined in the January 2026 brief, sought in this filing is $100 million, including a request to recover, over a 12-month period, $38 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. In November 2025, an intervenor proposed a $31 million reduction to the UTM deferral balance. The filing is currently undergoing a paper hearing and in January 2026 the parties filed briefs reiterating their position. A resolution is expected in the first half of 2026. 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 may defer up to 90% of all depreciation expense and return associated with qualifying electric plant to a regulatory asset, provided the utility has notified the OCC of its election to do so. SB 998 excludes deferral of costs 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. Through December 31, 2025, PSO deferred $9 million of qualifying costs to a regulatory asset to be recovered through future base rates. 55 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, Notice 2025-49. This guidance is not expected to have a material impact on the Registrants. 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. Midcontinent Grid Solutions Investment (Applies to AEP and Transource Energy) In 2025, Transource Energy and an affiliate of Berkshire Hathaway Energy formed Midcontinent Grid Solutions, LLC to participate in MISO’s 2024 Regional Transmission Expansion Plan competitive process. In January 2026, MISO selected the upgrades proposed by Midcontinent Grid Solutions to address forecasted reliability and load growth requirements. The projects awarded by MISO are estimated to cost approximately $1.2 billion and Transource Energy’s share of this investment is estimated to be $600 million. The projects awarded by MISO will be developed, owned and operated by Midcontinent Grid Solutions Wisconsin, LLC (MGS Wisconsin), a subsidiary of Midcontinent Grid Solutions, LLC. In May 2025, Midcontinent Grid Solutions, LLC’s subsidiary, Midcontinent Grid Solutions Iowa, LLC (MGS Iowa) submitted to FERC a request for acceptance of formula rates, consisting of a formula rate template and implementation protocols, effective July 2025. In September 2025, the FERC issued an order accepting the formula rate, granting MGS Iowa’s requested effective date of July 2025 and the following: (a) regulatory asset treatment for pre-commercial and formation costs with carrying charges, (b) a hypothetical capital structure of 60% equity and 40% debt through the date of the company’s first transmission project being placed in service, (c) conditional approval of a 50-basis point ROE adder due to participation in an RTO, effective upon the date on which operational control transitions to MISO, and (d) authorization of the company’s request to replicate its formula rate and related treatments for future subsidiaries in MISO. FERC also accepted MGS Iowa’s proposed use of a 9.98% base ROE, the MISO regional base ROE effective at the time of the FERC order, and the depreciation rates proposed by the company. As an affiliate of Midcontinent Grid Solutions Iowa, LLC (MGS Iowa), MGS Wisconsin is authorized to replicate MGS Iowa’s FERC-approved formula rate without further FERC approval. 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 structure, formula rate template language and depreciation rates. 56 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, offers data centers and other large customers this custom solution to support their growing energy needs while it completes grid infrastructure enhancements to accommodate demand. By the end of the first quarter of 2025, OPCo had signed two contracts totaling approximately 98 MWs 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. In January 2026, under the existing option to acquire additional fuel cells, an unregulated AEP subsidiary entered into an agreement to acquire solid oxide fuel cells for approximately $2.65 billion to develop a fuel cell generation facility near Cheyenne, Wyoming. The subsidiary also entered into a 20-year offtake agreement with an investment-grade customer for 100% of the facility’s output. The offtake arrangement is subject to certain conditions that AEP expects to be satisfied by the second quarter of 2026. If these conditions are not met, AEP will receive financial compensation for all capital and costs incurred. 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. For the year ended 2025, AEP issued 5,022,229 shares of common stock and received net cash proceeds of $500 million. As of December 31, 2025, AEP expects approximately $1.7 billion of net cash proceeds from the remaining physical settlement of the forward sale agreements and management anticipates using any future proceeds for general corporate purposes, capital investments, 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. 57 LITIGATION In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies for additional information. 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 6 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 evolve. AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units.  Management is engaged in the development of possible future requirements including the items discussed below. AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If AEP cannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition. Impact of Environmental Compliance on the Generating Fleet The rules and environmental control requirements discussed below will have a material impact on AEP’s operations.  As of December 31, 2025, AEP owned generating capacity of approximately 25,400 MWs, of which approximately 10,700 MWs were coal-fired.  In April 2024, the Federal EPA announced four major new rules directed at fossil-fuel electric generation facilities. Management continues to evaluate the impacts of these rules on the plans for the future of AEP’s generating fleet, in particular, the economic feasibility of making the requisite environmental investments in AEP’s fossil generation fleet. AEP continues to refine the cost estimates of complying with these rules to identify the best alternative for 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. 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 and localities implement and administer many of these programs and could impose additional or more stringent requirements. Primary CAA regulatory programs that continue to drive investments in AEP’s existing generating units include the following: (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 58 from fossil generation under Section 111 of the CAA. Certain 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 meet the new standard. In November 2025, in connection with pending litigation challenging the new standards, the Federal EPA filed a motion asking the court to vacate the stricter PM 2.5 standard. If the rule is not vacated, 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. Any nonattainment designations by the Federal EPA and the subsequent SIP revisions by affected states will take time to finalize and complete. Management cannot reasonably estimate any impacts 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 would require certain 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. The rules implementing the Regional Haze requirements of the CAA have been revisited over time. In January 2026, the Federal EPA published a final rule extending the due date for the next round of Regional Haze SIP submittals by states to July 31, 2031. 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 NO X 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 proposed to approve the Texas Regional Haze SIP. In December 2025, the Federal EPA finalized its approval of the Texas and Oklahoma SIPs. 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. New Source Performance Standards In January 2026, the Federal EPA finalized revisions to the New Source Performance Standards for stationary combustion turbine units that commenced construction, modification, or reconstruction after December 13, 2024. The new standards for NO X require a level of performance equivalent to the application of selective catalytic reduction for large, high-utilization natural gas-fired turbines, but establish various levels of combustion controls as the best system of emission reductions for smaller and lower-utilization turbines. The rule does not change the SO 2 limits applicable to combustion turbines. Management is evaluating the implications of the rule on new combustion turbine projects. 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 NO X 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. 59 In January 2021, the Federal EPA finalized a revised CSAPR, which substantially reduced the ozone season NO X budgets for several states, including states where AEP operates, beginning in ozone season 2021. AEP met the requirements of the revised rule over the first few years of implementation, and is evaluating its compliance options for future 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 NO X budgets under the existing CSAPR program in states to which the FIP applies. The FIP has since been administratively stayed pending the Supreme Court lifting its order staying enforcement of the Good Neighbor Plan, other courts lifting any judicial orders staying the SIP disapproval action as to the state, and the Federal EPA taking subsequent rulemaking action consistent with any judicial rulings on the merits. Additionally, in April 2025, the court placed the challenges to the Good Neighbor Plan in abeyance pending further order of the court. The Federal EPA has indicated it intends to propose rulemaking to revise the rule. Management will continue to monitor the 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. Twenty-seven states, numerous companies, trade associations and others challenged the rule. 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. The court has stayed the litigation pending rulemaking by the Federal EPA. In June 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. In July 2025, the Federal EPA proposed to repeal the 2009 Endangerment Finding, which determined that greenhouse gas emissions endanger public health and welfare. The 2009 Endangerment Finding is the basis of the 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 the Federal EPA’s authority to regulate greenhouse gas emissions from electric generators. Management cannot predict the outcome of the current litigation or the 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. More stringent rules directed at the fossil-fuel fired electric utility industry 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, APCo and I&M 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, which 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 60 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. 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 in 2015, the rule applied to active and inactive CCR landfills and surface impoundments at facilities of active electric utility or independent power producers. In August 2018, the District of Columbia Circuit Court vacated and remanded certain aspects of the 2015 CCR rule, including an exemption for legacy impoundments. Following this, the Federal EPA issued a final rule in August 2020, setting an April 11, 2021 deadline for unlined CCR impoundments to cease waste acceptance and commence closure. This rule permits a facility to request a deadline extension from the Federal EPA if alternative disposal capacity is unavailable or a compliant conversion or a plant retirement is in progress. In January 2022, the Federal EPA made public statements in the context of a deadline extension request submitted by the Gavin Power Station suggesting more stringent closure requirements for CCR units. See “Claims for Indemnification Made by Owners of the Gavin Power Station” above for additional information. In April 2022, a petition was filed with the District of Columbia Circuit Court of Appeals, arguing that the Federal EPA could not enforce these new purported requirements without proper rulemaking. In June 2024, the District of Columbia Circuit dismissed these petitions, finding the statements were not amendments to existing regulations and thus the court lacked jurisdiction. 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”). That rule has been challenged in the District of Columbia Circuit Court. 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. As a result, the litigation challenging the 2024 Legacy Rule is being held in abeyance. In November 2025, the Federal EPA proposed to extend by three years the compliance deadline applicable to certain facilities operating pursuant to alternative closure deadlines for unlined surface impoundments greater than 40 acres. In February 2026, the Federal EPA finalized a rule that provides additional time to meet facility evaluation requirements for identifying CCR management units and to comply with groundwater monitoring provisions. Additionally, this rule makes conforming changes to the remaining CCR management units compliance deadlines. Additional revisions to the CCR Rule are expected in 2026. Should additional corrective measures like groundwater treatment or ash removal be mandated at any of AEP’s coal-fired facilities, AEP could face substantial costs that could materially and adversely affect financial condition, results of operations, and cash flows. See “Federal EPA’s Revised CCR Rule” section in Note 6 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 61 eliminate the need to install zero liquid discharge systems for facilities that comply with the 2020 rule’s control technology requirements and have committed 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 also challenged the rule by filing a joint appeal with a utility trade association in which AEP participates. The litigation challenging the ELG Rule is being held in abeyance while the new administration evaluates the rule and the Federal EPA has subsequently announced plans to reconsider the standards and deadlines established by the 2024 ELG rule. Management cannot predict the outcome of the litigation. In December 2025, the Federal EPA issued the Deadline Extension ELG Rule 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. Management cannot predict the outcome of any further rulemaking actions by the Federal EPA related to the ELG rule. In January 2026, the Federal EPA proposed a rule titled Updating the Water Quality Certification Regulations. Through the proposed rule, the Federal EPA is attempting to clarify the Clean Water Act section 401 certification process for states and tribes. Under section 401, a federal agency cannot conduct any activity that may result in a discharge into waters of the United States without obtaining a permit from a State or authorized tribe in the location of the discharge certifying compliance with applicable water quality requirements. The proposed rule aims to reduce regulatory delays associated with the certification process. Management will monitor the rulemaking for any potential impacts to operations. The definition of “waters of the United States” has been subject to rulemaking and litigation which has led to inconsistent scope among the states. In November 2025, the Federal EPA and the United States Army Corps of Engineers proposed a revised definition of “waters of the United States” to conform to a decision by the United States Supreme Court. Management will continue to monitor developments in rulemaking 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 regularly 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. For generating facilities retired or planned for retirement in advance of the retirement date currently authorized for ratemaking purposes, with related accelerated depreciation regulatory assets pending regulatory approval, the table below summarizes the net book value and related regulatory asset balances recorded as of December 31, 2025: Company Plant Net Investment (a) Accelerated Depreciation Regulatory Asset Actual/Projected Retirement Date Current Authorized Recovery Period Annual Depreciation (b) (in millions) (in millions) PSO Northeastern Plant, Unit 3 $ 73  $ 221  2026 (c) $ 15 SWEPCo Pirkey Plant —  94  (d) 2023 (e) — SWEPCo Welsh Plant, Units 1 and 3 269  220  2028 (f) (g) 47 (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 Texas and FERC jurisdictional share. (e) 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 5 for additional information. In January 2026, the FERC issued an order providing recovery of the Pirkey Plant based on blended recovery periods determined by all SWEPCo jurisdictions including Texas. (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. 62 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. 63 RESULTS OF OPERATIONS AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity.  Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight applicable to each public utility subsidiary.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments are as follows: • Vertically Integrated Utilities • Transmission and Distribution Utilities • AEP Transmission Holdco • Generation & Marketing The remainder of AEP’s activities are presented as Corporate and Other, which is not considered a reportable segment. See Note 9 - 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 year ended December 31, 2025 as compared to the year ended December 31, 2024. For AEP’s Vertically Integrated Utilities and Transmission and Distribution Utilities segments and Registrant Subsidiaries within these segments, the results include revenues from rate rider mechanisms designed to recover fuel, purchased power and other recoverable expenses such that the revenues and expenses associated with these items generally offset and do not affect Earnings Attributable to AEP Common Shareholders. For additional information regarding the financial results for the years ended December 31, 2025 and 2024, see the discussions of Results of Operations by Registrant Subsidiary. 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 on Form 10-K filed with the SEC on February 13, 2025. The following table presents Earnings Attributable to AEP Common Shareholders by segment: Years Ended December 31, 2025 2024 2023 (in millions) Vertically Integrated Utilities $ 1,605  $ 1,453  $ 1,090 Transmission and Distribution Utilities 816  726  699 AEP Transmission Holdco 1,161  790  703 Generation & Marketing 287  289  (26) Corporate and Other (289) (291) (258) Earnings Attributable to AEP Common Shareholders $ 3,580  $ 2,967  $ 2,208 See Note 9 - 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. 64 VERTICALLY INTEGRATED UTILITIES Summary of KWh Energy Sales for Vertically Integrated Utilities Years Ended December 31, 2025 2024 2023 (in millions of KWhs) Retail: Residential 31,844  31,025  30,290 Commercial 26,295  24,647  23,481 Industrial 33,571  34,013  34,148 Miscellaneous 2,257  2,271  2,229 Total Retail 93,967  91,956  90,148 Wholesale (a) 16,039  14,523  13,401 Total KWhs 110,006  106,479  103,549 (a) Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers. Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities Years Ended December 31, 2025 2024 2023 (in degree days) Eastern Region Actual – Heating 2,741  2,092  1,992 Normal – Heating 2,646  2,704  2,719 Actual – Cooling 1,120  1,366  1,003 Normal – Cooling 1,110  1,114  1,119 Western Region Actual – Heating 1,354  1,052  1,068 Normal – Heating 1,436  1,450  1,464 Actual – Cooling 2,506  2,738  2,590 Normal – Cooling 2,307  2,289  2,277 65 Reconciliation of Year Ended December 31, 2024 to Year Ended December 31, 2025 Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities (in millions) Year Ended December 31, 2024 $ 1,453 Changes in Revenues: Retail Revenues 956 Off-system Sales 145 Transmission Revenues 113 Other Revenues 8 Total Change in Revenues 1,222 Changes in Expenses and Other: Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (260) Other Operation and Maintenance (356) Asset Impairments and Other Related Charges (21) Depreciation and Amortization (105) Taxes Other Than Income Taxes 3 Other Income (1) Allowance for Equity Funds Used During Construction 22 Non-Service Cost Components of Net Periodic Pension Cost 1 Interest Expense (132) Total Change in Expenses and Other (849) Income Tax Benefit (222) Net Income Attributable to Noncontrolling Interests 1 Year Ended December 31, 2025 $ 1,605 The major components of the increase in Revenues were as follows: • Retail Revenues increased $956 million primarily due to the following: • A $601 million increase in base rate and rider revenues. • A $148 million increase at SWEPCo due to a revenue refund provision recorded in 2024 associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case. • A $133 million increase in weather-normalized revenues primarily in the residential and commercial classes, partially offset by a decrease in the industrial class. • A $109 million increase in fuel revenues. • A $50 million increase in weather-related usage primarily in the residential class driven by a 30% increase in heating degree days. These increases were partially offset by: • An $86 million decrease due to regulatory provisions for refund at I&M. • Off-system Sales increased $145 million primarily due to economic hedging activity, Rockport Plant, Unit 2 merchant sales at I&M and capacity revenues recognized from the RPM auction for the 2025-2026 planning year at APCo. • Transmission Revenues increased $113 million primarily due to the following: • A $65 million increase due to continued transmission investment. • A $56 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates. • Other Revenues increased $8 million primarily due to gains from the sale of renewable energy credits. Expenses and Other and Income Tax Benefit changed between years as follows: • Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $260 million primarily due to increases at I&M and PSO, partially offset by decreases at APCo and SWEPCo. • Other Operation and Maintenance expenses increased $356 million primarily due to the following: • A $114 million increase in distribution expenses primarily due to vegetation management costs. • An $88 million increase in PJM and SPP transmission expenses. 66 • A $60 million increase in generation expenses. • A $60 million increase in employee-related expenses. • A $53 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates. • A $29 million increase in customer operations and services primarily due to recoverable energy assistance program expenses for qualified Virginia customers at APCo. These increases were partially offset by: • A $76 million decrease due to the voluntary severance program that occurred in the second quarter of 2024. • A $14 million decrease due to a disallowance recorded on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024. • Asset Impairments and Other Related Charges increased $21 million primarily due to the following: • A $34 million increase due to an impairment of in-process internal use software development costs. This increase was partially offset by: • A $13 million decrease due to the Federal EPA’s revised CCR rules finalized in 2024. • Depreciation and Amortization expenses increased $105 million   primarily due to the following: • A $117 million increase primarily due to a higher depreciable base at APCo, I&M, PSO and SWEPCo. • A $20 million increase at I&M due to a prior year deferral combined with current year amortization of Excess ADIT as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking. • A $20 million increase at SWEPCo due to the amortization of the Storm Recovery Funding securitized assets. These increases were partially offset by: • A $61 million decrease due to the under-recovery of regulatory assets related to renewables at PSO and SWEPCo. • Allowance for Equity Funds Used During Construction increased $22 million primarily due to increased AFUDC base and rates. • Interest Expense increased $132 million primarily due to higher long-term debt balances at APCo, PSO and SWEPCo and a prior year deferral of expenses as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking at I&M, PSO and SWEPCo. • Income Tax Benefit decreased $222 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 $78 million decrease due to an increase in pretax book income. • A $32 million decrease due to the reversal of a regulatory liability related to the merchant portion of Turk Plant Excess ADIT as a result of the APSC’s denial of SWEPCo’s request to allow the merchant portion of the Turk Plant to serve Arkansas customers recorded in 2024. These decreases were partially offset by: • A $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. 67 TRANSMISSION AND DISTRIBUTION UTILITIES Summary of KWh Energy Sales for Transmission and Distribution Utilities Years Ended December 31, 2025 2024 2023 (in millions of KWhs) Retail: Residential 27,437  26,782  26,099 Commercial 46,187  36,147  30,419 Industrial 28,020  27,368  26,571 Miscellaneous 728  742  745 Total Retail (a) 102,372  91,039  83,834 Wholesale (b) 2,250  2,014  1,922 Total KWhs 104,622  93,053  85,756 (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 Years Ended December 31, 2025 2024 2023 (in degree days) Eastern Region Actual – Heating 3,273  2,446  2,380 Normal – Heating 3,057  3,140  3,185 Actual – Cooling 1,098  1,300  842 Normal – Cooling 1,056  1,031  1,026 Western Region Actual – Heating 348  196  197 Normal – Heating 323  316  318 Actual – Cooling 2,956  3,249  3,208 Normal – Cooling 2,641  2,770  2,737 68 Reconciliation of Year Ended December 31, 2024 to Year Ended December 31, 2025 Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities (in millions) Year Ended December 31, 2024 $ 726 Changes in Revenues: Retail Revenues 195 Off-system Sales 56 Transmission Revenues 72 Other Revenues (84) Total Change in Revenues 239 Changes in Expenses and Other: Purchased Electricity for Resale (67) Purchased Electricity from AEP Affiliates 33 Other Operation and Maintenance (152) Asset Impairments and Other Related Charges 22 Depreciation and Amortization 59 Taxes Other Than Income Taxes (20) Other Income (8) Allowance for Equity Funds Used During Construction 8 Non-Service Cost Components of Net Periodic Benefit Cost 9 Interest Expense (18) Total Change in Expenses and Other (134) Income Tax Expense (18) Equity Earnings of Unconsolidated Subsidiaries 3 Year Ended December 31, 2025 $ 816 The major components of the increase in Revenues were as follows: • Retail Revenues increased $195 million primarily due to the following: • A $171 million increase in base case and rider revenues. • A $26 million increase in weather-related usage driven by a 34% increase in heating degree days in Ohio. These increases were partially offset by: • A $14 million decrease in weather-normalized revenues primarily in the residential class in Ohio. • Off-system Sales increased $56 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume. • Transmission Revenues increased $72 million primarily due to the following: • A $120 million increase primarily due to continued transmission investments. This increase was partially offset by: • A $48 million decrease due to lower peak loads included in 2025 billing rates in Texas. • Other Revenues decreased $84 million primarily due to the following: • A $74 million decrease in securitization revenues resulting from the maturity of Transition Funding III LLC securitization bonds in December 2024. • An $18 million decrease due to lower third-party Legacy Generation Resource Rider revenue as a result of approved legislation in Ohio in May 2025 which ended the retail recovery of OVEC purchased power costs. Expenses and Other and Income Tax Expense changed between years as follows: • Purchased Electricity for Resale expenses increased $67 million primarily due to the following: • A $35 million increase in recoverable auction purchases from nonaffiliates to serve SSO customers in Ohio. • 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 May 2025. • A $13 million increase in OVEC-related purchased power expenses. 69 • Purchased Electricity from AEP Affiliates expenses decreased $33 million primarily due to decreased recoverable auction purchases from AEP Energy Partners to serve SSO customers in Ohio. • Other Operation and Maintenance expenses increased $152 million primarily due to the following: • A $105 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses in Ohio. • A $54 million increase in recoverable Transmission Cost Recovery Factor expenses in Texas. • A $22 million increase in employee-related expenses. • A $19 million increase in transmission and distribution expenses in Texas. These increases were partially offset by: • A $35 million decrease due to the voluntary severance program that occurred in the second quarter of 2024. • A $29 million decrease related to recoverable energy assistance program expenses for qualified Ohio customers. • Asset Impairments and Other Related Charges decreased $22 million due to the following: • A $53 million decrease due to the Federal EPA’s revised CCR rules finalized in 2024. This decrease was partially offset by: • A $31 million increase due to an impairment of in-process internal use software development costs in 2025. • Depreciation and Amortization expenses decreased $59 million primarily due to the following: • A $71 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds. • A $23 million decrease due to the deferral of eligible costs related to the UTM. These decreases were partially offset by: • A $37 million increase due to a higher depreciable base in Texas. • Taxes Other Than Income Taxes increased $20 million primarily due to higher property taxes. • Other Income decreased $8 million primarily due to lower interest income as a result of lower advances to affiliates. • Allowance for Equity Funds Used During Construction increased $8 million due to a higher AFUDC base in Texas. • Non-Service Cost Components of Net Period Benefit Cost decreased $9 million primarily due to an increase in loss amortization for the plans and a plan remeasurement triggered by settlements related to the voluntary severance program in 2024, partially offset by lower interest costs due to lower discount rates. • Interest Expense increased $18 million primarily due to the following: • A $46 million increase due to higher long-term debt balances and interest rates. This increase was partially offset by: • A $28 million decrease due to the deferral of eligible costs related to the UTM. • Income Tax Expense increased $18 million primarily due to an increase in pretax book income. 70 AEP TRANSMISSION HOLDCO Summary of Investment in Transmission Assets for AEP Transmission Holdco December 31, 2025 2024 (in millions) Plant in Service $ 17,662  $ 15,835 Construction Work in Progress 2,167  2,206 Accumulated Depreciation and Amortization 1,968  1,626 Total Transmission Property, Net $ 17,861  $ 16,415 Reconciliation of Year Ended December 31, 2024 to Year Ended December 31, 2025 Earnings Attributable to AEP Members from AEP Transmission Holdco (in millions) Year Ended December 31, 2024 $ 790 Changes in Transmission Revenues: Transmission Revenues 426 Total Change in Transmission Revenues 426 Changes in Expenses and Other: Other Operation and Maintenance (31) Depreciation and Amortization (47) Taxes Other Than Income Taxes (13) Interest and Investment Income (5) Allowance for Equity Funds Used During Construction 4 Non-Service Cost Components of Net Periodic Pension Cost 4 Interest Expense (19) Total Change in Expenses and Other (107) Income Tax Expense 173 Equity Earnings of Unconsolidated Subsidiaries (12) Net Income Attributable to Noncontrolling Interests (109) Year Ended December 31, 2025 $ 1,161 The major components of the increase in Transmission Revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows: • Transmission Revenues increased $426 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 $212 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 $31 million primarily due to an increase in employee-related expenses, vegetation management expenses and other various miscellaneous expenses, partially offset by a decrease due to the voluntary severance program that occurred in the second quarter of 2024. • Depreciation and Amortization expenses increased $47 million primarily due to a higher depreciable base. • Taxes Other Than Income Taxes increased $13 million primarily due to higher property taxes driven by increased transmission investment. • Interest and Investment Income decreased $5 million   primarily due to lower advances to affiliates. • Interest Expense increased $19 million primarily due to higher long-term debt balances and interest rates. 71 • Income Tax Expense decreased $173 million primarily due to the following: • A $254 million decrease due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates. This decrease was partially offset by: • A $64 million increase due to an increase in pretax book income. • A $15 million increase due to an increase in state taxes. • Equity Earnings of Unconsolidated Subsidiaries decreased $12 million primarily due to lower pretax earnings by ETT and PATH-WV. • Net Income Attributable to Noncontrolling Interests increased $109 million primarily due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025. 72 GENERATION & MARKETING Reconciliation of Year Ended December 31, 2024 to Year Ended December 31, 2025 Earnings Attributable to AEP Common Shareholders from Generation & Marketing (in millions) Year Ended December 31, 2024 $ 289 Changes in Revenues: Merchant Generation 90 Renewable Generation (24) Retail, Trading and Marketing 651 Total Change in Revenues 717 Changes in Expenses and Other: Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (783) Other Operation and Maintenance 47 Asset Impairments and Other Related Charges 76 Depreciation and Amortization 5 Interest and Investment Income (1) Non-Service Cost Components of Net Periodic Benefit Cost (2) Interest Expense 9 Total Change in Expenses and Other (649) Income Tax Expense (69) Equity Earnings of Unconsolidated Subsidiaries (1) Year Ended December 31, 2025 $ 287 The major components of the increase in Revenues were as follows: • Merchant Generation increased $90 million primarily due to higher realized prices in 2025. • Renewable Generation decreased $24 million primarily due to the sale of AEP Onsite Partners in September 2024. • Retail, Trading and Marketing increased $651 million primarily due to higher market prices in 2025. Expenses and Other and Income Tax Expense changed between years as follows: • Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $783 million primarily due to an increase in energy costs in 2025. • Other Operation and Maintenance expenses decreased $47 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 Expense decreased $9 million primarily due to lower advances from affiliates. • Income Tax Expense increased $69 million primarily due to the following: • 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 $14 million increase due to an increase in pretax book income. 73 CORPORATE AND OTHER 2025 Compared to 2024 Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $291 million in 2024 to a loss of $289 million in 2025 primarily due to: • A $21 million decrease in interest expense primarily due to lower short-term debt balances and interest rates. • A $19 million loss contingency recorded in 2024 associated with the SEC investigation. • An $18 million increase in equity earnings. • An $11 million increase due to the recognition of deferred revenues for completed agreements. These increases in earnings were partially offset by: • A $31 million decrease in Income Tax Benefit primarily due to an increase in state taxes. • A $30 million decrease in interest income primarily due to lower advances to affiliates. • A $7 million decrease at EIS primarily due to increased insurance reserves. AEP CONSOLIDATED INCOME TAXES 2025 Compared to 2024 • Income Tax Expense increased $168 million primarily due to the following: • A $212 million increase due to a reduction in Excess ADIT regulatory liabilities at I&M, PSO and SWEPCo as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking recorded in 2024. • A $187 million increase due to an increase in pretax book income. • A $54 million increase due to a decrease in amortization of deferred ITCs primarily due to the sale of NMRD and Onsite Partners in 2024. • A $32 million increase due to a reduction in Excess ADIT regulatory liabilities as a result of the APSC’s denial of SWEPCo’s request to allow the merchant portion of the Turk Plant to serve Arkansas customers recorded in 2024. • A $29 million increase due to a decrease in amortization of Excess ADIT. • A $15 million increase due to an increase in state taxes. These increases were partially offset by: • A $368 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. FINANCIAL CONDITION AEP measures financial condition by the strength of its balance sheet and the liquidity provided by its cash flows. SIGNIFICANT CASH REQUIREMENTS AEP’s contractual cash obligations include amounts reported on the balance sheets and other obligations disclosed in the footnotes. It is anticipated that these obligations will be satisfied through a combination of cash flows from operations, long-term debt issuances, short-term debt through AEP’s Commercial Paper Program or bank term loans, the use of the ATM Program, the March 2025 forward sale of equity agreement or other equity issuances. Capital Expenditures Continued capital investments reflect AEP’s dedication to enhance service and deliver safe, reliable power to customers. In October 2025, AEP announced a $72 billion capital plan for 2026-2030 driven by transmission and distribution infrastructure upgrades and new generation to support anticipated load growth. See “Budgeted Capital Expenditures” herein, for additional information. Long-term Debt Long-term debt maturities, including interest, represent a significant cash requirement for AEP and the Registrant Subsidiaries. See Note 15 - Financing Activities for additional information relating to the Registrant Subsidiaries’ long-term debt outstanding as of December 31, 2025, the weighted-average interest rate applicable to each debt category and a schedule of debt maturities over the next five years. 74 Other Significant Cash Requirements Operating and finance leases represent a significant component of funding requirements for AEP and the Registrant Subsidiaries. See Note 13 - Leases for additional information. AEP subsidiaries have substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. See Note 6 - Commitments, Guarantees and Contingencies for additional information. As of December 31, 2025, AEP expected to make contributions to the pension plans totaling $83 million in 2026. Estimated contributions of $84 million in 2027 and $85 million in 2028 may vary significantly based on market returns, changes in actuarial assumptions and other factors. Based upon the projected benefit obligation and fair value of assets available to pay pension benefits, the pension plans were 98% funded as of December 31, 2025. See “Estimated Future Benefit Payments and Contributions” section of Note 8 for additional information. Standby letters of credit are entered into with third-parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt security reserves. There is no collateral held in relation to any guarantees in excess of the ownership percentages. In the event any letters of credit are drawn, there is no recourse to third-parties. See “Letters of Credit” section of Note 6 for additional information. LIQUIDITY AND CAPITAL RESOURCES Debt and Equity Capitalization December 31, 2025 2024 (dollars in millions) Long-term Debt, including amounts due within one year $ 47,322  58.4  % $ 42,643  59.1  % Short-term Debt 1,508  1.9  2,524  3.5 Total Debt 48,830  60.3  45,167  62.6 AEP Common Equity 31,138  38.4  26,944  37.3 Noncontrolling Interests 1,080  1.3  42  0.1 Total Debt and Equity Capitalization $ 81,048  100.0  % $ 72,153  100.0  % AEP’s ratio of debt-to-total capital decreased from 62.6% to 60.3% as of December 31, 2024 and December 31, 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 for the foreseeable future. As of December 31, 2025, AEP had $6 billion in revolving credit facilities to support its commercial paper program. Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, long-term asset securitizations, leasing agreements, hybrid securities or common stock. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that there is an increase in interest rates, it could reduce future net income and cash flows and impact financial condition. In addition, 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. 75 Net Available Liquidity AEP manages liquidity by maintaining adequate external financing commitments.  As of December 31, 2025, available liquidity was approximately $5.6 billion as illustrated in the table below: Amount Maturity (a) (in millions) Commercial Paper Backup: Revolving Credit Facility $ 5,000  March 2029 Revolving Credit Facility 1,000  March 2027 Cash and Cash Equivalents 197 Total Liquidity Sources 6,197 Less: AEP Commercial Paper Outstanding 605 Net Available Liquidity $ 5,592 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 2025 was $2.9 billion.  The average amount of commercial paper outstanding during 2025 was $1.4 billion. The weighted-average yield for AEP’s commercial paper during 2025 was 4.47%. Other Credit Facilities An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. As of December 31, 2025, 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 December 31, 2025 was $377 million with maturities ranging from January 2026 to November 2026. Financing Plan As of December 31, 2025, AEP had $3.2 billion of long-term debt due within one year. This included $1.6 billion of Senior Unsecured Notes, $1.1 billion of Term Loans, $240 million of Pollution Control Bonds with mandatory tender dates and credit support for variable interest rates that require the debt to be classified as current and $204 million of securitization bonds and DCC Fuel notes. Management plans to replace or refinance substantially all of the maturities due within one year on a long-term basis. Securitized Accounts Receivables AEP Credit’s receivables securitization agreement provides a commitment of $900 million from bank conduits to purchase receivables and expires in September 2027. As of December 31, 2025, the affiliated utility subsidiaries were in compliance with all requirements under the agreement. Debt Covenants and Borrowing Limitations AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements.  Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of December 31, 2025, this contractually-defined percentage was 54.7%. 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. 76 March 2025 Forward Sale of Equity See “Forward Sale of Equity” section of Note 15 for additional information regarding AEP’s forward sale of 22,549,020 shares of common stock in March 2025. ATM Program AEP participates in an ATM offering program that allows AEP to issue, from time to time, shares of its common stock, including shares of common stock that may be sold pursuant to an equity forward sales agreement. As of December 31, 2025, approximately $3.5 billion of equity is available for issuance under the ATM offering program. See “ATM Program” section of Note 15 - Financing Activities for additional information. Dividend Policy and Restrictions The Board of Directors declared a quarterly dividend of $0.95 per share in January 2026.  Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 15 for additional information. Credit Ratings AEP and its utility subsidiaries do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but its access to the commercial paper market may depend on its credit ratings.  In addition, downgrades in AEP’s credit ratings by one of the rating agencies could increase its borrowing costs.  Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject AEP to additional collateral demands under adequate assurance clauses under its derivative and non-derivative energy contracts. 77 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. Years Ended December 31, 2025 2024 2023 (in millions) Cash, Cash Equivalents and Restricted Cash at Beginning of Period $ 246  $ 379  $ 557 Net Cash Flows from Operating Activities 6,944  6,804  5,012 Net Cash Flows Used for Investing Activities (11,939) (7,596) (6,267) Net Cash Flows from Financing Activities 5,017  659  1,077 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 22  (133) (178) Cash, Cash Equivalents and Restricted Cash at End of Period $ 268  $ 246  $ 379 Operating Activities Years Ended December 31, 2025 2024 2023 (in millions) Net Income $ 3,696  $ 2,976  $ 2,213 Non-Cash Adjustments to Net Income (a) 3,621  3,383  3,376 Mark-to-Market of Risk Management Contracts (116) (81) 9 Pension Contributions to Qualified Plan Trust (95) —  — Property Taxes (42) (45) (41) Deferred Fuel Over/Under Recovery, Net 133  277  893 Change in Other Noncurrent Assets (b) (863) (522) (762) Change in Other Noncurrent Liabilities 269  306  29 Change in Certain Components of Working Capital 341  510  (705) Net Cash Flows from Operating Activities $ 6,944  $ 6,804  $ 5,012 (a) Includes Depreciation and Amortization, Deferred Income Taxes, Loss on the Sale of the Competitive Contracted Renewables Portfolio, Asset Impairments and Other Related Charges, Allowance for Equity Funds Used During Construction and Amortization of Nuclear Fuel. (b) Includes Change in Regulatory Assets. 2025 Compared to 2024 Net Cash Flows from Operating Activities increased by $140 million primarily due to the following: • A $958 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 $341 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 and Note 5 - Effects of Regulation for additional information. • A $169 million decrease in cash from the Change in Certain Components of Working Capital primarily due to an increase in fuel, material and supplies driven by higher coal inventory on hand, the timing of accounts receivable collections and changes in income tax payments and tax credits. These decreases were partially offset by the timing of accounts payable, employee-related benefits, proceeds received from the sale of transferable tax credits and increased margin deposits driven by increases in power prices. • A $144 million decrease in cash primarily due to the timing of fuel and purchased power revenues and expenses. • A $95 million decrease in cash due to a discretionary contribution to the qualified pension plan. See Note 8 - Benefit Plans for additional information. 78 Investing Activities Years Ended December 31, 2025 2024 2023 (in millions) Construction Expenditures $ (8,453) $ (7,631) $ (7,378) Acquisitions of Nuclear Fuel (130) (140) (128) Acquisitions of Generation Facilities (3,453) (399) (155) Proceeds from Sales of Assets 25  362  1,341 Proceeds from Sale of Equity Method Investment —  114  — Other 72  98  53 Net Cash Flows Used for Investing Activities $ (11,939) $ (7,596) $ (6,267) 2025 Compared to 2024 Net Cash Flows Used for Investing Activities increased by $4.3 billion primarily due to the following: • A $3.1 billion increase in Acquisitions of Generation Facilities. • An $822 million increase in Construction Expenditures primarily due to increases in Vertically Integrated Utilities of $636 million and Transmission and Distribution Utilities of $634 million partially offset by decreases in Corporate and Other of $429 million driven by expenditures for fuel cell generation assets in 2024. • A $337 million decrease in Proceeds from Sale of Assets primarily due to the sale of AEP OnSite Partners in 2024. • A $114 million decrease in Proceeds from the Sale of AEP’s Equity Investment in NMRD. See Note 7 - Acquisitions, Dispositions and Impairments for additional information. Financing Activities Years Ended December 31, 2025 2024 2023 (in millions) Issuance of Common Stock $ 775  $ 552  $ 1,000 Issuance/Retirement of Debt, Net 3,596  2,126  1,985 Principal Payments for Finance Lease Obligations (51) (65) (68) Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs 2,783  —  — Dividends Paid on Common Stock (2,008) (1,898) (1,752) Other (78) (56) (88) Net Cash Flows from Financing Activities $ 5,017  $ 659  $ 1,077 2025 Compared to 2024 Net Cash Flows from Financing Activities increased by $4.4 billion primarily due to the following: • A $3.1 billion increase in issuances of long-term debt. • A $2.8 billion increase due to proceeds from the Midwest Transmission Holdings Noncontrolling Interest transaction. See “Noncontrolling Interest in Midwest Transmission Holdings” section of Note 7 for additional information. These increases in cash were partially offset by: • A $964 million increase in retirements of long-term debt. • A $710 million decrease due to changes in short-term debt. The following financing activities occurred during 2025: AEP Common Stock: • During 2025, AEP issued 8 million shares of common stock under the Forward Sale of Equity, ATM offering program, incentive compensation, employee saving and dividend reinvestment plans. See “Common Stock” section of Note 15 for additional information. AEP received net proceeds of $775 million related to these issuances. 79 Debt: • During 2025, AEP issued approximately $8.3 billion of long-term debt, including $3 billion of junior subordinated notes at interest rates ranging from 5.80% to 6.05%, $2.2 billion of other debt at various interest rates, $2.1 billion of senior unsecured notes at interest rates ranging from 5.38% to 5.85%, $478 million of securitization bonds at an interest rate of 5.30%, $320 million of pollution control bonds at interest rates ranging from 3.30% to 3.70% and $203 million of notes payable at various interest rates. • During 2025, settlements of AEP’s interest rate derivatives resulted in net cash paid of $40 million for derivatives designated as fair value hedges.  As of December 31, 2025, AEP had a total notional amount of $500 million of outstanding interest rate derivatives designated as fair value hedges. See “Financing Activities Subsequent Events” section of Note 15 for Long-term debt and other securities issued, retired and principal payments made after December 31, 2025 through February 12, 2026, the date that the 10-K was issued. BUDGETED CAPITAL EXPENDITURES Management forecasts approximately $12.2 billion of capital expenditures in 2026.  For the four-year period, 2027 through 2030, management forecasts capital expenditures of $59.7 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, technology advancements, 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 estimated capital expenditures by Business Segment are as follows: 2026 Budgeted Capital Expenditures 2027-2030 Segment Environmental Generation Renewables Transmission Distribution Other (a) Total Total (in millions) VIU $ 97  $ 2,144  $ 1,173  $ 1,187  $ 1,733  $ 364  $ 6,698  $ 30,457 T&D —  —  —  1,576  1,683  295  3,554  18,983 AEPTHCo —  —  —  1,454  —  32  1,486  9,122 G&M —  —  —  —  —  21  21  91 Corporate and Other —  117  —  —  —  355  472  1,082 Total $ 97  $ 2,261  $ 1,173  $ 4,217  $ 3,416  $ 1,067  $ 12,231  $ 59,735 (a) Amount primarily consists of facilities, software and telecommunications. The 2026 estimated capital expenditures by Registrant Subsidiary are as follows: 2026 Budgeted Capital Expenditures Company Environmental Generation Renewables Transmission Distribution Other (a) Total (in millions) AEP Texas $ —  $ —  $ —  $ 1,208  $ 949  $ 194  $ 2,351 AEPTCo —  —  —  1,326  —  29  1,355 APCo 58  158  387  358  449  107  1,517 I&M 3  1,237  4  160  362  66  1,832 OPCo —  —  —  368  734  101  1,203 PSO 4  305  738  172  412  66  1,697 SWEPCo 17  361  44  360  323  106  1,211 (a) Amount primarily consists of facilities, software and telecommunications. 80 CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies.  Management considers an accounting estimate to be critical if: • It requires assumptions to be made that were uncertain at the time the estimate was made; and • Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition. Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosures relating to them. Management believes that the current assumptions and other considerations used to estimate amounts reflected in the financial statements are appropriate.  However, actual results can differ significantly from those estimates. The sections that follow present information about critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate. Regulatory Accounting Nature of Estimates Required The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. The Registrants recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation.  Specifically, the timing of expense and income recognition is matched with regulated revenues.  Liabilities are also recorded for refunds, or probable refunds, to customers that have not been made. Assumptions and Approach Used When incurred costs are probable of recovery through regulated rates, regulatory assets are recorded on the balance sheets.  Management reviews the probability of recovery at each balance sheet date and whenever new events occur.  Similarly, regulatory liabilities are recorded when a determination is made that a refund is probable or when ordered by a commission.  Examples of new events that affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation.  The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs as well as the return of revenues, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates.  If recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings.  A write-off of regulatory assets or establishment of a regulatory liability may also reduce future cash flows since there will be no recovery through regulated rates. Effect if Different Assumptions Used A change in the above assumptions may result in a material impact on net income.  See Note 5 - Effects of Regulation for additional information related to regulatory assets and regulatory liabilities. Revenue Recognition – Unbilled Revenues Nature of Estimates Required AEP recognizes revenues from customers as the performance obligations of delivering energy to customers are satisfied.  The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded.  This estimate is reversed in the following month and actual revenue is recorded based on meter readings.  PSO and SWEPCo do not include the fuel portion in unbilled revenue in accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas. 81 Accrued unbilled revenues for the Vertically Integrated Utilities segment were $387 million and $351 million as of December 31, 2025 and 2024, respectively. The changes in unbilled electric utility revenues for AEP’s Vertically Integrated Utilities segment were $36 million, $63 million and $(66) million for the years ended December 31, 2025, 2024 and 2023, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather, rates and usage. Accrued unbilled revenues for the Transmission and Distribution Utilities segment were $206 million and $199 million as of December 31, 2025 and 2024, respectively. The changes in unbilled electric utility revenues for AEP’s Transmission and Distribution Utilities segment were $7 million, $8 million and $(30) million for the years ended December 31, 2025, 2024 and 2023, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather, rates and usage. Accrued unbilled revenues for the Generation & Marketing segment were $159 million and $121 million as of December 31, 2025 and 2024, respectively. The changes in unbilled electric utility revenues for AEP’s Generation & Marketing segment were $38 million, $10 million and $2 million for the years ended December 31, 2025, 2024 and 2023, respectively. Assumptions and Approach Used For each Registrant except AEPTCo, the monthly estimate for unbilled revenues is based upon a primary computation of net generation (generation plus purchases less sales) less the current month’s billed KWhs and estimated line losses, plus the prior month’s unbilled KWhs. However, due to the potential for meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon an allocation of billed KWhs to the current month and previous month, on a billing cycle-by-cycle basis, and by dividing the current month aggregated result by the billed KWhs. The two methodologies are evaluated to confirm that they are not statistically different. For AEP’s Generation & Marketing segment, management calculates unbilled revenues based on a primary computation of load as provided by PJM less the current month’s billed KWhs and estimated line losses, plus the prior month’s unbilled KWhs. However, due to the potential for meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon using the most recent historic daily activity on a per contract basis. The two methodologies are evaluated to confirm that they are not statistically different. Effect if Different Assumptions Used For each Registrant except AEPTCo, if the two methodologies used to estimate unbilled revenue are statistically different, a limiter adjustment is made to bring the primary computation within one standard deviation of the secondary computation. Additionally, significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the estimate of unbilled revenue. Accounting for Derivative Instruments Nature of Estimates Required Management considers fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates.  These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors. Assumptions and Approach Used The Registrants measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based primarily on exchange prices and broker quotes.  If a quoted market price is not available, the fair value is estimated based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions.  Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment.  These uncertainties include forward market price assumptions. The Registrants reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality.  Liquidity adjustments are calculated by utilizing bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time.  Credit adjustments on risk management contracts are calculated using estimated default probabilities and recovery rates relative to the counterparties or counterparties with similar credit profiles and contractual netting agreements. 82 With respect to hedge accounting, management assesses hedge effectiveness and evaluates a forecasted transaction’s probability of occurrence within the specified time period as provided in the original hedge documentation. Effect if Different Assumptions Used There is inherent risk in valuation modeling given the complexity and volatility of energy markets.  Therefore, it is possible that results in future periods may be materially different as contracts settle. The probability that hedged forecasted transactions will not occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into Operating Income. For additional information see Note 10 - Derivatives and Hedging and Note 11 - Fair Value Measurements.  See “Fair Value Measurements of Assets and Liabilities” section of Note 1 for AEP’s fair value calculation policy. Long-Lived Assets Nature of Estimates Required In accordance with the requirements of “Property, Plant and Equipment” accounting guidance and “Regulated Operations” accounting guidance, the Registrants evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable. Such events or changes in circumstance include planned abandonments, probable disallowances for ratemaking purposes of assets determined to be recently completed plant and assets that meet the held-for-sale criteria.  The Registrants utilize a group composite method of depreciation to estimate the useful lives of long-lived assets. An impairment evaluation of a long-lived, held and used asset may result from an abandonment, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses.  If the book value of the asset is not recoverable through estimated, future undiscounted cash flows, the Registrants record an impairment to the extent that the fair value of the asset is less than its book value.  Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets and developing the non-discounted and discounted future cash flows (used to estimate fair value in the absence of market-based value, in some instances) associated with the asset.  Assets held for sale must be measured at the lower of the book value or fair value less cost to sell. An impairment is recognized if an asset’s fair value less costs to sell is less than its book value. Any impairment charge is recorded as a reduction to earnings. Assumptions and Approach Used The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, the Registrants estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals.  Cash flow estimates are based on relevant information available at the time the estimates are made.  Estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.  Also, when measuring fair value, management evaluates the characteristics of the asset or liability to determine if market participants would take those characteristics into account when pricing the asset or liability at the measurement date.  Such characteristics include, for example, the condition and location of the asset or restrictions on the use of the asset.  The Registrants perform depreciation studies that include a review of any external factors that may affect the useful life to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions for regulated assets.  The fair value of the asset could be different using different estimates and assumptions in these valuation techniques. Effect if Different Assumptions Used In connection with the evaluation of long-lived assets in accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the fair value of the asset can vary if different estimates and assumptions are used in the applied valuation techniques.  Estimates for depreciation rates contemplate the history of interim capital replacements and the amount of salvage expected.  In cases of impairment, the best estimate of fair value was made using valuation methods based on the most current 83 information at that time.  Differences in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, the timing and terms of the transactions and management’s analysis of the benefits of the transaction. 84 Pension and OPEB AEPSC maintains a qualified, defined benefit pension plan (Qualified Plan), which covers substantially all nonunion and certain union employees, and unfunded, non-qualified supplemental plans (Nonqualified Plans) to provide benefits in excess of amounts permitted under the provisions of the tax law for participants in the Qualified Plan (collectively the Pension Plans).  AEPSC also sponsors OPEB plans to provide health and life insurance benefits for retired employees.  The Pension Plans and OPEB plans are collectively referred to as the Plans. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.  See Note 8 - Benefit Plans for information regarding costs and assumptions for the Plans. The following table shows the net periodic cost (credit) of the Plans: Years Ended December 31, Net Periodic Cost (Credit) 2025 2024 2023 (in millions) Pension Plans $ 42  $ 86  $ (24) OPEB (78) (71) (107) The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets.  In developing the expected long-term rate of return assumption for 2026, management evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions.  Management also considered historical returns of the investment markets and tax rates which affect a portion of the OPEB plans’ assets.  Management anticipates that the investment managers employed for the Plans will invest the assets to generate future returns averaging 6.75% for the Qualified Plan and 6% for the OPEB plans. The expected long-term rate of return on the Plans’ assets is based on management’s targeted asset allocation and expected investment returns for each investment category.  Assumptions for the Plans are summarized in the following table: Pension Plans OPEB Assumed/Expected Assumed/Expected 2026 Target Long-Term 2026 Target Long-Term Asset Allocation Rate of Return Asset Allocation Rate of Return Equity 35  % 8.50  % 63  % 7.52  % Fixed Income 49  % 5.31  % 36  % 4.56  % Other Investments 15  % 8.78  % —  — Cash and Cash Equivalents 1  % 3.00  % 1  % 3.00  % Total 100  % 100  % Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation.  Management believes that 6.75% for the Qualified Plan and 6% for the OPEB plans are reasonable estimates of the long-term rate of return on the Plans’ assets.  The Pension Plans’ assets had an actual gain of 10.52% and an actual gain of 2.59% for the years ended December 31, 2025 and 2024, respectively.  The OPEB plans’ assets had an actual gain of 14.72% and an actual gain of 8.98% for the years ended December 31, 2025 and 2024, respectively.  Management will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary. AEP bases the determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.  Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.  As of December 31, 2025, AEP had cumulative losses of approximately $196 million for the Qualified Plan that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized market-related net actuarial losses may result in increases in the future pension costs depending on several factors, including whether such losses at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance. 85 The method used to determine the discount rate that AEP utilizes for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.  The discount rate as of December 31, 2025 under this method was 5.5% for the Qualified Plan, 5.3% for the Nonqualified Plans and 5.5% for the OPEB plans.  Due to the effect of the unrecognized net actuarial losses and based on an expected rate of return, discount rates and various other assumptions, management estimates costs (credits) for the Pension Plans will approximate $87 million, $139 million and $142 million in 2026, 2027 and 2028, respectively.  Based on an expected rate of return discount rate and various other assumptions, management estimates OPEB plan credits will approximate $90 million, $85 million and $91 million in 2026, 2027 and 2028, respectively. Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans.  The actuarial assumptions used may differ materially from actual results.  The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below. The value of AEP’s Pension Plans’ assets is $3.8 billion as of December 31, 2025 and $3.7 billion as of December 31, 2024.  During 2025, the Qualified Plan paid $374 million and the Nonqualified Plans paid $8 million in benefits to plan participants.  The value of AEP’s OPEB plans’ assets increased to $2.0 billion as of December 31, 2025 from $1.8 billion as of December 31, 2024 primarily due to positive investment returns. During 2025, the OPEB plans paid $105 million in benefits to plan participants. Nature of Estimates Required AEPSC sponsors pension and OPEB plans in various forms covering all employees who meet eligibility requirements.  These benefits are accounted for under “Compensation” and “Plan Accounting” accounting guidance.  The measurement of pension and OPEB obligations, costs and liabilities is dependent on a variety of assumptions. Assumptions and Approach Used The critical assumptions used in developing the required estimates includes discount rate, compensation increase rate, cash balance crediting rate, health care cost trend rate and expected return on plan assets. Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience. Effect if Different Assumptions Used The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants.  These differences may result in a significant impact to the amount of pension and OPEB expense recorded.  If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows: Pension Plans OPEB +0.5% -0.5% +0.5% -0.5% (in millions) Effect on December 31, 2025 Benefit Obligations Discount Rate $ (164) $ 179  $ (23) $ 25 Compensation Increase Rate 23  (22) NA NA Cash Balance Crediting Rate 48  (45) NA NA Health Care Cost Trend Rate NA NA 5  (5) Effect on 2025 Periodic Cost Discount Rate $ (9) $ 10  $ (1) $ 1 Compensation Increase Rate 6  (5) NA NA Cash Balance Crediting Rate 11  (10) NA NA Health Care Cost Trend Rate NA NA 1  (1) Expected Return on Plan Assets (20) 20  (9) 9 NA    Not applicable. 86 Asset Retirement Obligations – Impact of the 2024 CCR Rule Nature of Estimates Required In April 2024, the Federal EPA finalized revisions to the CCR Rule to expand the scope of the rule to include inactive impoundments at inactive facilities as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land. Accounting for the incremental asset retirement obligation arising from the revised CCR Rule requires significant judgment by management due to the significant measurement uncertainty in estimating the incremental liability. As a result of the rule, AEP recorded an incremental ARO of $674 million in the second quarter of 2024. Assumptions and Approach Used AROs are computed as the present value of the estimated costs associated with the future retirement of an asset and are recorded in the period in which the liability is incurred. Projections of the timing and amounts of future cash outlays are based on estimation of the extent and quantity of coal ash present at sites, projections of the when and how the liabilities will be remediated as well as the rate at which costs will escalate over time and discount rate, which may change significantly over time. Effect if Different Assumptions Used As further groundwater monitoring and other analysis is performed, management expects to refine the assumptions and underlying cost estimates used in recording the incremental asset retirement obligation arising from the revised CCR Rule. The estimated liability can significantly change if there are changes in the impacted coal ash site acreage inputs or if refinements in the assumptions over the remediation costs for legacy CCR surface impoundments and CCR management units, including assumptions over future groundwater monitoring requirements vary from the initial estimates. These future changes could have a material impact on the ARO and materially reduce future net income, cash flows and financial condition if AEP cannot ultimately recover these additional costs of compliance. See Note 6 – Commitments, Guarantees and Contingencies and Note 19 – Property, Plant and Equipment for additional information related to AROs and the CCR Rule. ACCOUNTING STANDARDS See Note 2 - New Accounting Standards for information related to accounting standards and SEC rulemaking activity. 87 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Market Risks Market risk evaluations are subject to certain limitations that may prevent a full reflection of the net market risk exposure. These limitations primarily relate to model and data constraints that rely on hypothetical assumptions and may not capture all potential future market conditions. These include the use of historical information, assumptions about market volatility and correlations, and dependence on observable inputs that may not be available for less liquid positions. As a result, the actual impact of market movements could differ from the estimates presented. The Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through transactions in power, coal, natural gas and marketing contracts. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates. The Transmission and Distribution Utilities segment is exposed to energy procurement risk and interest rate risk. The Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. This segment is exposed to certain market risks as a marketer of wholesale and retail electricity. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates. In addition, the Generation & Marketing segment is also exposed to certain market risks as a power producer and through transactions in wholesale electricity, natural gas and marketing contracts. Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts.  Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business.  As a result, AEP is subject to price risk.  The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the AEP Board.  AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Regulated Risk Committee and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, Executive Vice President and Chief Commercial Officer, Senior Vice President and Treasurer, Senior Vice President of Regulated Commercial Operations, President AEP Transmission, and Senior Vice President Finance. The Competitive Risk Committee consists of AEPSC’s Chief Financial Officer, Executive Vice President and Chief Commercial Officer, Senior Vice President and Treasurer, and Senior Vice President of Competitive Commercial Operations.  If commercial activities result in predetermined limits being exceeded, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee. 88 The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2024: MTM Derivative Contract Net Assets (Liabilities) Year Ended December 31, 2025 Vertically Integrated Utilities Transmission and Distribution Utilities Generation & Marketing Total (in millions) Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of December 31, 2024 $ 92  $ (48) $ 162  $ 206 (Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period (79) 2  (39) (116) Fair Value of New Contracts at Inception When Entered During the Period (a) —  —  12  12 Changes in Fair Value Due to Market Fluctuations During the Period (b) (10) —  73  63 Changes in Fair Value Allocated to Regulated Jurisdictions (c) 140  13  —  153 Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of December 31, 2025 $ 143  $ (33) $ 208  $ 318 Commodity Cash Flow Hedge Contracts 98 Fair Value Hedge Contracts (29) Collateral Deposits (80) Total MTM Derivative Contract Net Assets as of December 31, 2025 $ 307 (a) Reflects fair value on primarily auctions or long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  The contract prices are valued against market curves associated with the delivery location and delivery term.  A significant portion of the total volumetric position has been economically hedged. (b) Market fluctuations are attributable to various factors such as supply/demand, weather, etc. (c) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable on the balance sheet. See Note 10 – Derivatives and Hedging and Note 11 – Fair Value Measurements for additional information related to risk management contracts.  The following tables and discussion provide information on credit risk and market volatility risk. Credit Risk Credit risk is mitigated in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. AEP has risk management contracts (including non-derivative contracts) with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily.  As of December 31, 2025, credit exposure net of collateral to sub-investment grade counterparties was approximately 10.6%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss). 89 As of December 31, 2025, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable: Counterparty Credit Quality Exposure Before Credit Collateral Credit Collateral Net Exposure Number of Counterparties

10% of Net Exposure Net Exposure of Counterparties 10% (in millions, except number of counterparties) Investment Grade $ 564  $ 76  $ 488  3  $ 301 Non-investment Grade 5  1  4  2  4 No External Ratings: Internal Investment Grade 18  —  18  3  12 Internal Non-investment Grade 126  70  56  2  48 Total as of December 31, 2025 $ 713  $ 147  $ 566 All exposure in the table above relates to AEPSC and AEPEP as AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries and AEPEP is agent for, and transacts on behalf of, other AEP subsidiaries. In addition, AEP is exposed to credit risk related to participation in RTOs.  For each of the RTOs in which AEP participates, this risk is generally determined based on the proportionate share of member gross activity over a specified period of time. Value at Risk (VaR) Associated with Risk Management Contracts Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, as of December 31, 2025, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition. Management calculates the VaR for both a trading and non-trading portfolio. The trading portfolio consists primarily of contracts related to energy trading and marketing activities. The non-trading portfolio consists primarily of economic hedges of generation and retail supply activities. The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated: VaR Model Trading Portfolio Twelve Months Ended Twelve Months Ended December 31, 2025 December 31, 2024 End High Average Low End High Average Low (in millions) (in millions) $ —  $ 1  $ —  $ —  $ —  $ 2  $ —  $ — VaR Model Non-Trading Portfolio Twelve Months Ended Twelve Months Ended December 31, 2025 December 31, 2024 End High Average Low End High Average Low (in millions) (in millions) $ 4  $ 29  $ 8  $ 2  $ 38  $ 99  $ 19  $ 8 Management back-tests VaR results against performance due to actual price movements.  Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days. 90 As the VaR calculation captures recent price movements, management also performs regular stress testing of the trading portfolio to understand AEP’s exposure to extreme price movements.  A historical-based method is employed whereby the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss.  Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee, Regulated Risk Committee or Competitive Risk Committee as appropriate. Interest Rate Risk AEP is exposed to interest rate market fluctuations in the normal course of business operations. Prior to 2022, interest rates remained at low levels and the Federal Reserve maintained the federal funds target range at 0.0% to 0.25% for much of 2021. During 2022 and 2023, the Federal Reserve approved 11 rate increases for a total cumulative increase of 5.25%. In light of the progress on inflation and the balance of risks, the Federal Reserve authorized three rate cuts in 2024, totaling a cumulative decrease of 1.0%. In 2025, the Federal Reserve authorized three additional interest rate cuts, totaling a cumulative 0.75%. AEP has outstanding short and long-term debt which is subject to variable rates. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes on interest rates. For the twelve months ended December 31, 2025, 2024 and 2023, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $36 million, $33 million and $40 million, respectively. 91