AEP Texas Inc.

•Retail Revenues decreased $19 million primarily due to the following:

•A $13 million decrease in weather-related usage primarily due to a 51% decrease in heating degree days.

•A $9 million decrease in rider revenues.

•Transmission Revenues increased $13 million primarily due to increased transmission investments.

•Other Revenues increased $7 million primarily due to the taxable portion of payments received from customers for large interconnection projects.

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

•Interest Expense decreased $7 million primarily due to the following:

•A $12 million decrease due to the deferral of eligible costs related to the UTM.

•A $6 million increase primarily due to higher long-term debt balances.

•Income Tax Expense increased $7 million primarily due to an increase in pretax book income.

ASSETS

Summary of Investment in Transmission Assets for AEPTCo

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

•Transmission Revenues increased $51 million primarily due to increased transmission investments.

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

•Other Operation and Maintenance expenses increased $17 million primarily due to an increase in employee-related costs, vegetation management expenses and other miscellaneous expenses.

•Depreciation and Amortization expenses increased $14 million primarily due to a higher depreciable base.

•Taxes Other than Income Taxes increased $14 million primarily due to higher property taxes driven by higher transmission investments.

•Interest Expense increased $10 million primarily due to higher long-term debt balances and interest rates.

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

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

ASSETS

LIABILITIES AND MEMBER’S EQUITY

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

•Retail Revenues decreased $16 million primarily due to the following:

•A $55 million decrease in fuel revenues.

•A $25 million increase in base rate and rider revenues.

•A $10 million increase in weather-normalized margins primarily driven by the commercial and industrial classes.

•Transmission Revenues increased $14 million primarily due to continued transmission investment.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $43 million primarily due to an increase in under-recovered deferred fuel regulatory assets primarily driven by lower authorized fuel rates in Virginia.

•Other Operation and Maintenance expenses increased $16 million primarily due to the following:

•A $14 million increase in transmission expenses primarily due to increases in vegetation management, storm restoration expenses and recoverable PJM expenses.

•A $12 million increase in distribution expenses primarily due to an increase in storm-related expenses and vegetation management costs.

•A $7 million increase in administrative and general expenses primarily due to employee-related costs.

•A $3 million increase in steam generation expenses primarily due to increased plant maintenance.

•A $23 million gain from the sale of a non-utility investment in land.

•Depreciation and Amortization expenses increased $5 million primarily due to the following:

•A $27 million increase primarily due to the cumulative regulatory deferral true-up for the impact of CAMT expense incurred related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•A $24 million decrease due to an April 2026 order approving a final true-up to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner.

•Taxes Other Than Income Taxes increased $6 million primarily due to higher business and occupation taxes.

•Interest Expense increased $8 million primarily due to higher long-term debt balances.

•Income Tax Expense decreased $29 million primarily due to the following:

•A $21 million decrease due to the cumulative true-up of CAMT related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•A $7 million decrease due to an increase in PTCs.

•A $5 million decrease due to an increase in amortization of Excess ADIT.

ASSETS

•Retail Revenues increased $128 million primarily due to the following:

•A $55 million increase in weather-normalized revenues primarily in the commercial class.

•A $47 million increase in rider revenues.

•An $18 million increase in fuel revenues.

•A $9 million increase due to a decrease in regulatory provisions for refund.

•Off-system Sales increased $82 million primarily due to Rockport Plant, Unit 2 merchant sales during Winter Storm Fern in January 2026, partially offset by economic hedging activity.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $56 million primarily due to an increase in recoverable fuel and purchased power costs and an increase in Rockport Plant, Unit 2, merchant generation fuel costs.

•Other Operation and Maintenance expenses increased $33 million primarily due to the following:

•An $11 million increase in distribution expenses primarily due to an increase in vegetation management costs and other distribution-related expenses.

•An $11 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $5 million increase in nuclear expenses at Cook Plant.

•A $4 million increase in demand side management expenses.

•A $7 million decrease due to an increased Nuclear Electric Insurance Limited distribution.

•Depreciation and Amortization increased $7 million primarily due to the following:

•A $5 million increase due to NOLC-related Excess ADIT deferrals recorded in 2025 and the amortization of these deferrals recorded in 2026 for IURC approved recovery through I&M’s Indiana tax rider.

•A $2 million increase due to a higher depreciable base.

•Interest Expense increased $8 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $19 million primarily due to the following:

•A $23 million increase due to an increase in pretax book income.

•A $6 million decrease due to an increase in PTCs.

ASSETS

(dollars in millions)

(a)Represents energy delivered to distribution customers.

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

•Retail Revenues increased $52 million primarily due to the following:

•A $51 million increasedue to higher prices for purchased power to serve OPCo’s SSO customers.

•A $14 million increase in weather-normalized revenues primarily in the residential class.

•A $15 million decrease in weather-related usage driven by a 2% decrease in heating degree days.

•Off-system Sales increased$25 million primarily due to increased sales of OVEC purchased power driven by higher market prices.

•Transmission Revenues increased$7 million primarily due to increased transmission investments.

•Purchased Electricity for Resale increased $4 million primarily due to the following:

•A $51 million increase in recoverable auction purchases to serve SSO customers.

•A $35 million decrease due to the prior year reduction in regulatory assets for OVEC-related purchased power costs that were no longer probable of recovery due to approved legislation in Ohio in May 2025.

•A $9 million decrease due to the elimination of an OVEC-related regulatory mechanism in August 2025 as a result of approved legislation in Ohio in May 2025.

•A $5 million decrease in OVEC purchased power costs.

•Other Operation and Maintenance expenses increased $8 million primarily due to the following:

•A $10 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•An $8 million increase in distribution expenses primarily due to recoverable vegetation management expenses.

•A $10 million decrease in transmission expenses primarily due to a $21 million decrease in recoverable PJM expenses, partially offset by a $9 million increase in recoverable storm restoration costs and vegetation management expenses.

•Depreciation and Amortization expenses increased $17 million primarily due to the deferral of income tax benefit from Excess ADIT credits to be refunded to customers as approved in the 2025 base rate case.

•Non-Service Cost Components of Net Periodic Benefit Cost expenses decreased $5 million primarily due to the deferral of pension settlement expense approved in the 2025 base rate case.

•Income Tax Expense decreased $2 million primarily due to the following:

•A $12 million decrease from Excess ADIT credits to be refunded to customers as approved in the 2025 base rate case.

•An $11 million increase due to an increase in pretax book income.

ASSETS

(dollars in millions)

(a)Includes municipalities and cooperatives, unit power and other wholesale customers.

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

•Retail Revenues increased $44 million primarily due to the following:

•A $62 million increase in rider revenues.

•An $8 million decrease in weather-normalized revenues primarily in the residential class partially offset by an increase in the industrial class.

•A $6 million decrease in weather-related usage primarily due to a 35% decrease in heating degree days.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $35 million primarily due to increased recoverable PTCs.

•Other Operation and Maintenance expenses increased $37 million primarily due to the following:

•A $20 million increasein transmission expenses primarily due to SPP expenses.

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

•A $5 million increase in distribution expenses primarily due to overhead line maintenance.

•Depreciation and Amortization expenses increased $4 million primarily due to the following:

•A $16 million increase due to a higher depreciable base.

•An $11 million decrease primarily due to higher under-recovery of costs and allowable return associated with the renewable rider.

•Taxes Other Than Income Taxes increased $5 million primarily due to property taxes on acquired generation facilities.

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

•Income Tax Benefit increased $38 million primarily due to the following:

•A $27 million increase due to an increase in PTCs.

•An $11 million increase due to a decrease in pretax book income.

CONDENSED STATEMENTS OF INCOME

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

CONDENSED STATEMENTS OF CHANGES IN

CONDENSED BALANCE SHEETS

ASSETS

CONDENSED BALANCE SHEETS

CONDENSED STATEMENTS OF CASH FLOWS

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

•Retail Revenues increased $21 million primarily due to the following:

•A $36 million increase in Arkansas base case and rider revenues.

•A $19 million increase in weather-normalized revenues primarily in the commercial and industrial classes.

•A $26 million decrease in fuel revenue primarily due to the refund of the Texas over-recovered fuel balance.

•A $10 million decrease in weather-related usage primarily due to a 31% decrease in heating degree days.

•Transmission Revenues increased $19 million primarily due to a $12 million increase in continued transmission investment and a $5 million increase in transmission reservation revenue.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $20 million primarily due to the following:

•A $31 million decrease in fuel revenues primarily due to the amortization of a Texas fuel regulatory liability as a result of the refund of previously over-recovered fuel balances and lower authorized rates in Arkansas.

•A $6 million decrease due to a prior year Texas fuel disallowance.

These decreases were partially offset by:

•A $15 million increase in non-recoverable fuel costs primarily in Louisiana.

•An $8 million increase in recoverable PTCs.

•Other Operation and Maintenance expenses increased $32 million primarily due to the following:

•A $13 million increase in transmission expenses primarily due to SPP expenses.

•A $7 million increase in distribution expenses primarily due to overhead line maintenance.

•A $5 million increase in renewable generation operation and maintenance expenses.

•Asset Impairments and Other Related Charges increased $31 million due to the probable partial disallowance of the Pirkey Plant net book value in the 2025 Texas Base Rate Case.

•Depreciation and Amortization expenses increased $23 million primarily due to the following:

•A $15 million increase due to a higher depreciable base.

•A $7 million increase primarily due to higher over-recovery of costs and allowable return associated with the renewable rider inclusive of $29 million of higher PTCs.

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

•Interest Expense increased $11 million primarily due to higher long-term debt balances.

•Income Tax Benefit increased $43 million primarily due to the following:

•A $32 million increase due to an increase in PTCs.

•A $7 million increase due to a decrease in pretax book income.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

ASSETS

LIABILITIES AND EQUITY

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS

The condensed notes to condensed financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise:

1. SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2026 is not necessarily indicative of results that may be expected for the year ending December 31, 2026. The condensed financial statements are unaudited and should be read in conjunction with the audited 2025 financial statements and notes thereto, which are included in the 2025 Annual Reports.

Change in Presentation

In 2025, the Company changed its rounding presentation in the Registrant’s financial statements and accompanying tabular footnote disclosures to the nearest whole number in millions, except per share data. The change had no material impact on previously reported financial information, however, certain amounts reported for prior periods may differ by insignificant amounts due to the rounding presentation. In addition, historical percentages and per share amounts presented may not recalculate due to rounding. This change does not impact the comparability of the Registrant’s financial statements and related disclosures.

Earnings Per Share (EPS) (Applies to AEP)

Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted-average outstanding common shares, assuming conversion of all potentially dilutive securities. Dilutive securities are primarily related to forward sale of equity agreements and restricted stock units. See Note 12 - Financing Activities for more information regarding the forward sale of equity agreements.

The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:

There wereno antidilutive shares outstanding as of March 31, 2026 and 2025.

Restricted Cash (Applies to AEP, AEP Texas, APCo and SWEPCo)

Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds.

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statements of cash flows:

Supplementary Cash Flow Information (Applies to AEP)

2. NEW ACCOUNTING STANDARDS

Management reviews the FASB’s standard-setting process and the SEC’s rulemaking activity to determine the relevance, if any, to the Registrants’ business. The following standards/rules will impact the Registrants’ financial statements.

SEC Climate Disclosure Rule

In March 2024, the SEC adopted final rules that would require registrants to disclose certain climate-related information in registration statements and annual reports. Litigation challenging the new rules was filed by multiple parties in multiple jurisdictions, which have been consolidated and assigned to the U.S. Court of Appeals for the Eighth Circuit. In March 2025, the SEC announced that it voted to end its defense of the final climate disclosure rules. In April 2025, 18 states filed a motion to intervene in the case and to hold the case in abeyance until the SEC takes action to amend or rescind the rules. In July 2025, the SEC filed a status report stating that it does not intend to review or reconsider the rules and asked the Court of Appeals to make a ruling on the case. In September 2025, the Court of Appeals issued an order holding the case in abeyance until the SEC either formally defends the rules or initiates a new rulemaking process for reconsideration.

ASU 2024-03 “Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures” (ASU 2024-03)

In November 2024, the FASB issued ASU 2024-03, the intent of which is to improve financial reporting and respond to investor input by requiring public business entities to disclose additional information about certain expenses in the notes to financial statements in interim and annual reporting periods. Among other provisions, the new standard requires disclosure of disaggregated amounts for expenses such as employee compensation, depreciation, and intangible asset amortization included in each expense caption presented on the face of the income statement. Public business entities are required to include certain amounts that are already required to be disclosed under GAAP in the same disclosure as the other disaggregation requirements as well as a qualitative description of any amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. The new standard also requires disclosure of the total amount of selling expenses and, in annual reporting periods, an entity’s definition of selling expenses. An entity is not precluded from providing additional voluntary disclosures that may provide investors with additional decision-useful information.

The amendments in the new standard are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The amendments in the new standard should be applied either prospectively to financial statements issued for reporting periods after the effective date or retrospectively to any or all prior periods presented in the financial statements. Management is evaluating the new standard and has not yet determined when, or the method by which, the Registrants will adopt its amendments.

ASU 2025-06 “Intangibles—Goodwill and Other—Internal-Use Software” (ASU 2025-06)

In September 2025, the FASB issued ASU 2025-06, the intent of which is to modernize the cost capitalization threshold for internal-use software development costs by removing all references to software project development stages and providing new guidance on how to evaluate whether the probable-to-complete recognition threshold has been met for the commencement of capitalization of eligible costs.

The amendments in the new standard may be applied on either a retrospective, prospective or modified prospective basis for public business entities for fiscal years beginning after December 15, 2027 with early adoption permitted. Management elected to early adopt this standard prospectively beginning on January 1, 2026. The adoption of the new standard did not have a material impact on the results of operations, statements of financial position or cash flows.

3. COMPREHENSIVE INCOME

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

Presentation of Comprehensive Income

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

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

4. RATE MATTERS

As discussed in the 2025 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2025 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2026 and updates the 2025 Annual Report.

Regulated Generating Units (Applies to AEP, PSO and SWEPCo)

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management regularly evaluates cost estimates of complying with these regulations in balance with reliability and other factors, which has resulted in, and in the future may result in, a proposal to retire generating facilities earlier than their currently estimated useful lives.

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

Regulated Generating Unit that has been Retired and Related Fuel Operations

SWEPCo

In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or is seeking recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of March 31, 2026, SWEPCo’s share of the net investment in the Pirkey Plant was $172 million, including materials and supplies, net of cost of removal. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions.

As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment of the Pirkey Plant net investment. SWEPCo requested recovery including a weighted average cost of capital carrying charge in its 2025 Arkansas Base Rate Case. In January 2026, the APSC approved a settlement agreement providing for the recovery of the Pirkey Plant net investment over 10 years with a 3% return, and the agreement also included a provision that the retirement of the Pirkey Plant was prudent.

As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana jurisdictional share of the Pirkey Plant, through a separate rider, through 2032.

In July 2023, the LPSC ordered that a separate proceeding be established to review the prudence of the decision to retire the Pirkey Plant, including the costs included in fuel for years starting in 2019 and after. In April 2025, the LPSC determined the retirement of the Pirkey Plant was reasonable and prudent and authorized continued recovery of and on the remaining balance of the Pirkey Plant at SWEPCo’s weighted average cost of capital through 2032.

In July 2023, Texas ALJs issued a PFD that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected the July 2023 PFD conclusion. 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. In April 2026, a unanimous settlement in principle was reached related to the 2025 Texas Base Rate Case. In March 2026, SWEPCo recorded approximately $31 million for a probable partial regulatory disallowance of the Pirkey Plant. See the “2025 Texas Base Rate Case” section below for additional information. As of March 31, 2026, the Texas jurisdictional share of the net book value of the Pirkey Plant was $46 million. To the extent the PUCT does not accept the settlement and any costs included in this filing are not approved for recovery as a result of the final PUCT order, it could reduce future net income and cash flows and impact financial condition.

Regulated Generating Units to be Retired

PSO

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset.

Following the 2024 Oklahoma Base Rate Case, PSO continues to recover Northeastern Plant, Unit 3 through 2040. In April 2025, PSO and the ODEQ finalized a second amended regional haze agreement that would allow continued operation of the Northeastern Plant, Unit 3, on natural gas, through May 31, 2041. This agreement is contingent upon approval by the Federal EPA in the form of a revised SIP, which the ODEQ has submitted. In anticipation of approval from the Federal EPA, PSO began operating Northeastern Plant, Unit 3 on natural gas in January 2026. In the first quarter of 2026, PSO retired $325 million of coal-related assets at Northeastern Plant, Unit 3, resulting in a decrease to both Total Property, Plant and Equipment and Accumulated Depreciation and Amortization. As of March 31, 2026, the unrecovered value of these assets was $152 million, inclusive of ARO costs, which PSO is currently collecting in rates.

SWEPCo

In November 2020, management announced that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation. In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively. In February 2026, the APSC issued an order approving the application for a CCN.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of March 31, 2026, of generating facilities planned for retirement:

(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.

(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with the removal of Northeastern Plant, Unit 3, after retirement.

(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.

(d)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with the removal of Welsh Plant, Units 1 and 3, after retirement.

(e)Represents projected retirement date of coal assets.

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

Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except OPCo)

(a)In April 2026, the WVPSC issued an order that affirms previously approved MRBC revenue requirements and allows APCo to perform a final true-up to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner. The timing of recovery through the ENEC will be determined in the Companies’ 2026 ENEC proceeding. See “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” section below for additional information.

(b)In March 2026, the WVPSC issued a financing order approving a securitization that includes $40 million of West Virginia jurisdictional storm operation and maintenance costs that are subject to a final review by the WVPSC after bond pricing.

(c)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

(d)In November 2025, the Virginia SCC issued a financing order approving a securitization that includes $141 million of storm operation and maintenance costs that are subject to a final review by the Virginia SCC after bond pricing.

(e)Approved for collection through rates, subject to refund, for the Oklahoma and SWEPCo-Texas jurisdictions.

(a)In April 2026, the WVPSC issued an order that affirms previously approved MRBC revenue requirements and allows APCo to perform a final true-up to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner. The timing of recovery through the ENEC will be determined in the Companies’ 2026 ENEC proceeding. See “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” section below for additional information.

(b)In November 2025, the Virginia SCC issued a financing order approving a securitization that includes $141 million of storm operation and maintenance costs that are subject to a final review by the Virginia SCC after bond pricing.

(c)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

(d)In March 2026, the WVPSC issued a financing order approving a securitization that includes $40 million of West Virginia jurisdictional storm operation and maintenance costs that are subject to a final review by the WVPSC after bond pricing.

(a)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

(a)Approved for collection through rates, subject to refund.

(a)Approved for collection through rates, subject to refund, for Texas jurisdiction.

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Rate Matters (Applies to AEP and AEP Texas)

AEP Texas Interim Transmission and Distribution Rates

Through March 31, 2026, AEP Texas’ cumulative revenues from transmission and distribution interim base rate increases that are subject to review are estimated to be approximately $159 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition.

2025 UTM Filing

In October 2025, AEP Texas submitted its first filing with the PUCT seeking recovery of eligible costs through the UTM. In March 2026, a Texas ALJ issued a PFD recommending partial disallowance of the requested amounts. In April 2026, AEP Texas filed responses reflective of the legislative intent of Texas House Bill 5247 (2025). The impact of the final decision, and any potential retroactive impacts, as authorized by the PUCT, will be reflected in AEP Texas’ financial statements in the period in which a final decision is issued. A decision is expected in the second quarter of 2026.

In March 2026, AEP Texas began billing interim rates subject to refund as part of the UTM filing. If the PUCT issues a ruling that differs from AEP Texas’ position, a refund or billing credit could be required. 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. AEP Texas deferred approximately $80 million of eligible costs through March 31, 2026 as a regulatory asset. If any of these deferred costs are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

2021-2023 ENEC Remand Cases

In January 2024, the WVPSC issued an order resolving APCo’s and WPCo’s (the Companies) 2021-2023 ENEC cases. In the order, the WVPSC: (a) disallowed $232 million in ENEC under-recovered costs as of February 28, 2023 ($136 million related to APCo) and (b) approved the recovery of $321 million of ENEC under-recovered costs as of February 28, 2023 ($174 million related to APCo) plus a 4% debt carrying charge rate over aten-year recovery period starting September 1, 2024.

In February 2024, the Companies filed briefs with the West Virginia Supreme Court (WVSC) to initiate an appeal of the January 2024 order. Following arguments that were held in September 2024, the WVSC issued a November 2024 opinion affirming in part and reversing in part the WVPSC’s January 2024 ENEC order. The WVSC remanded the ENEC case to the WVPSC to afford the Companies an opportunity to examine, analyze, rebut and refute the calculation of the $232 million disallowance.

In March 2025, the WVPSC entered an order in the Companies’ 2021-2023 ENEC remand cases further describing its calculations of the ordered $232 million disallowance. In June 2025, the Companies submitted direct testimony on remand supporting a reduction to the WVPSC’s previously ordered disallowance of at least $179 million.

In August 2025, WVPSC staff and an intervening party submitted testimony recommending the continued disallowance of $232 million of ENEC under-recovered costs as of February 28, 2023, with the intervening party recommending that the WVPSC consider a larger disallowance based on alleged imprudence of coal procurement.

A hearing on the 2021-2023 ENEC remand cases was held in October 2025. If any additional 2021-2023 ENEC costs are not recoverable or refunds are ordered, it would reduce future net income and cash flows and impact financial condition.

2024 West Virginia Base Rate Case

In September 2025, and in response to the WVPSC’s August 2025 order on the Companies’ 2024 West Virginia Base Rate Case, petitions for reconsideration were filed with the WVPSC to explain the financial consequences of the order and seek clarification on certain issues. In February 2026, the WVPSC issued an order upon reconsideration approving a revised ROE of 9.75%. This approved change in ROE results in a revision to the approved annual increase in base rates from $76 million ($67 million related to APCo) to $91 million ($79 million related to APCo) effective February 20, 2026. All other requests for reconsideration were rejected by the WVPSC.

West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing

In March 2024, APCo and WPCo (the Companies) submitted an annual MRBC surcharge update filing with the WVPSC requesting a $32 million annual increase in the Companies’ combined MRBC rates. The MRBC is an infrastructure investment tracker that allows limited cost recovery related to capital investments between the Companies’ West Virginia jurisdictional base rate cases. WVPSC staff and an intervening party recommended revenue requirement disallowances in written and verbal testimony and briefs for certain ratemaking issues used to develop the Companies’ proposed MRBC rates, including the West Virginia jurisdictional effect of state deferred income taxes, NOLCs and AROs.

The WVPSC’s August 2025 order on the Companies’ West Virginia base case filing, as described in the “2024 West Virginia Base Rate Case” section above, approved the termination of the MRBC and the transition of MRBC rates into base rates. The WVPSC did not rule on MRBC refunds proposed by WVPSC staff and an intervening party related to NOLCs and other issues.

In April 2026, the WVPSC issued an order that adjudicated the Companies’ 2024 MRBC update filing. This order affirms previously approved MRBC revenue requirements and allows the Companies to perform a final true-up in an ENEC filing to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner during thefour-year existence of the surcharge. This order also allows the Companies to recognize a carrying charge on revised MRBC under-recovery balances starting September 2024 and for the Companies to recover the updated MRBC under-recovery with carrying charges through current ENEC surcharge rates over a period to be determined in the Companies’ 2026 ENEC proceeding. The April 2026 order also noted that collection of revenue requirement related to inclusion of a stand-alone NOLC deferred tax asset in MRBC rates may be subject to refund, pending the future issuance of a PLR or other guidance by the IRS. If any refund liabilities are imposed by the WVPSC related to NOLC, it could reduce future net income and cash flows and impact financial condition.

2025 West Virginia Securitization Filing

In March 2026, the WVPSC issued a final financing order approving the Companies’ proposed securitization of the following: (a) remaining combined unrecovered ENEC balances, (b) undepreciated West Virginia jurisdictional plant balances as of December 31, 2022 for the Amos, Mitchell and Mountaineer Plants, (c) undepreciated environmental costs previously approved for recovery through a separate West Virginia surcharge and (d) West Virginia jurisdictional deferred major storm operation and maintenance costs. As included in the WVPSC’s March 2026 order, shown below is a summary of the Companies’ combined $2.6 billion maximum securitization amount:

(a)Amounts represent estimates. The WVPSC may update these estimates prior to securitization bond marketing.

(b)In December 2025, the KPSC approved KPCo’s request for a CPCN to make investments necessary for KPCo to resume: (a) a 50% share of the Mitchell Plant ELG Project and (b) a 50% share of non-ELG capital investments. This approval by the KPSC allows KPCo to continue taking a 50% share of energy and capacity from the Mitchell Plant to serve KPCo customers beyond December 31, 2028. See “Mitchell Plant Filing for Certificate of Public Convenience and Necessity” section below for additional information. In February 2026, WPCo requested that the WVPSC grant any additional authorizations necessary to enable WPCo to reflect the holdings and impact of the December 2025 KPSC order or make a determination that no such authorizations are required. WPCo forecasted CCR and ELG amounts related to the Mitchell Plant are subject to change pending a ruling from the WVPSC on WPCo’s February 2026 filing.

In accordance with the West Virginia statutory requirements and the financing order, the issuance of the securitization bonds is subject to final review by the WVPSC after bond pricing. The Companies will proceed with the securitization bond issuance process and plan to complete the securitization in the second 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.

2025 Virginia Securitization Filing

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 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 second quarter 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.

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through March 31, 2026, AEP’s share of ETT’s cumulative revenues from interim base rate increases that are subject to a prudency review is approximately $1 million. A base rate review could produce a refund to customers if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition.

2026 ETT Base Rate Case

In April 2026, ETT filed a request with the PUCT for a $42 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request is based upon a proposed 10.5% ROE with a capital structure of 55% debt and 45% common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates. A procedural schedule for the case is pending. If any of the costs in the case are not recoverable or refunds collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition.

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

Michigan Power Supply Cost Recovery (PSCR) Reconciliation

2024 PSCR Reconciliation

In March 2025, I&M submitted its 2024 PSCR Reconciliation to the MPSC. In October 2025, MPSC staff and intervenors submitted testimony recommending PSCR cost disallowances associated with the OVEC ICPA and the Rockport UPA with AEGCo ranging from $259 thousand to $14 million. A hearing on I&M’s 2024 PSCR Reconciliation was held in December 2025. In April 2026, an ALJ issued a PFD recommending a $2 million cost disallowance associated with the OVEC ICPA and no cost associated with the Rockport UPA with AEGCo. An MPSC order is expected in the second quarter of 2026. Any future disallowances ordered by the MPSC on I&M’s 2024 PSCR Reconciliation could reduce future net income and cash flows and impact financial condition.

Indiana Earnings Test

I&M is required by Indiana law to submit an earnings test evaluation for the most recent one-year and five-year periods as part of I&M’s semi-annual Indiana FAC filings. These earnings test evaluations require I&M to include a credit in the FAC factor computation for periods in which I&M earned above its authorized return for both the one-year and five-year periods. The credit is determined as 50% of the lower of the one-year or five-year earnings above the authorized level. Management believes its financial statements adequately address the impact of Indiana earnings test requirements previously established by the IURC. If future IURC orders require that I&M provide credits in the FAC factor computation in excess of established earnings test requirements, it could reduce future net income and cash flows and impact financial condition.

In February 2026, I&M submitted its FAC filing and earnings test evaluation for the period ended November 2025. I&M proposed an over-earnings credit to customers for the earnings test period ending November 2025 of $53 million based on requested modifications to jurisdictional cost allocations to more accurately reflect I&M’s cost to serve Indiana retail customers. In April 2026, I&M and an intervening party submitted a settlement agreement recommending that the IURC approve I&M’s proposed modifications to jurisdictional cost allocations and proposed over-earnings credit of $53 million for the earnings test period ending November 2025. A hearing will be held in May 2026 and an IURC order is expected in the second quarter of 2026. An IURC order approving I&M’s proposed jurisdictional cost allocation modifications as included in the settlement agreement would increase future net income and cash flows and impact financial condition.

KPCo Rate Matters (Applies to AEP)

Investigation of the Service, Rates and Facilities of KPCo

In June 2023, the KPSC issued an order directing KPCo to show cause why it should not be subject to Kentucky statutory remedies, including fines and penalties, for failure to provide adequate service in its service territory. The KPSC’s show cause order did not make any determination regarding the adequacy of KPCo’s service. In July 2023, KPCo filed a response to the show cause order demonstrating that it has provided adequate service. In December 2023 and February 2024, KPCo and certain intervenors filed testimony with the KPSC. A hearing with the KPSC was previously scheduled to occur in June 2024. The hearing was postponed and has not yet been rescheduled. If any fines or penalties are levied against KPCo relating to the show cause order, it could reduce future net income and cash flows and impact financial condition.

Mitchell Plant Filing for Certificate of Public Convenience and Necessity

KPCo and WPCo each own a 50% undivided interest in the 1,560 MW coal-fired Mitchell Plant. In July 2021, the KPSC rejected KPCo’s ELG compliance plan for KPCo’s 50% ownership share of ELG investments at the Mitchell Plant that would allow KPCo to take capacity and energy to serve customers beyond December 31, 2028. As a result of this order, and pursuant to September 2022 resolutions under the existing Mitchell Plant Operating Agreement, WPCo funded 100% of the Mitchell Plant ELG investments that have been placed in service. In addition, WPCo also paid for a greater than 50% share of certain non-ELG capital investments made at Mitchell Plant which will continue to be used in the operation of Mitchell Plant beyond 2028.

In June 2025, KPCo filed a request with the KPSC for a CPCN to make investments necessary to reflect: (a) a 50% share of the Mitchell Plant ELG Project and (b) a 50% share of non-ELG capital investments. KPSC approval of these investments would allow KPCo to continue taking a 50% share of energy and capacity from the Mitchell Plant to serve KPCo customers beyond December 31, 2028. KPCo proposed to recover the estimated $78 million investment in the ELG Project through KPCo’s existing Environmental Surcharge and requested recovery of an estimated $60 million of Mitchell Plant non-ELG capital investments through its 2025 Kentucky Base Rate Case filing. See “2025 Kentucky Base Rate Case” section below for additional information.

In November 2025, KPCo and an intervening party submitted a settlement agreement that recommended the approval of KPCo’s proposed Mitchell Plant CPCN and use of KPCo’s Environmental Surcharge to recover Mitchell Plant ELG project costs through 2040. The settlement agreement further recommended granting KPCo authority to defer the depreciation expense and carrying costs associated with Mitchell Plant non-ELG capital investments to a regulatory asset until it can be reflected in rates. The recovery mechanism for Mitchell Plant non-ELG capital investments will be addressed in KPCo’s 2025 Kentucky Base Rate Case filing. See “2025 Kentucky Base Rate Case” section below for additional information.

In December 2025, the KPSC issued an order approving the settlement agreement, the Mitchell Plant CPCN and recovery of ELG capital investments through the Environmental Surcharge. The KPSC’s order imposes annual reporting requirements to review capital investment costs at the Mitchell Plant.

To operate in accordance with KPSC and WVPSC directives related to Mitchell Plant ELG investments, KPCo and WPCo expect to utilize existing authority under the Mitchell Plant Operating Agreement to revise billing procedures resulting in equal allocation of costs. In February 2026, WPCo requested that the WVPSC grant any additional authorizations necessary to enable WPCo to reflect the holdings and impact of the December 2025 KPSC order or make a determination that no such authorizations are required. As of March 31, 2026, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal and including CWIP and inventory, and prior to the effect of revised billing procedures expected under the Mitchell Plant Operating Agreement to comply with the KPSC’s December 2025 order, was $517 million.

2025 Kentucky Base Rate Case

In August 2025, KPCo filed a request with the KPSC for a $96 million net annual increase in base rates based upon a proposed 10% ROE and a proposed capital structure of 53.9% debt and 46.1% common equity, to be implemented no earlier than March 2026. Among other changes, the filing proposed a $10 million increase in PJM transmission costs, a $9 million increase due to load loss and a $6 million increase in depreciation rates.

The proposed annual rate increase also included a $20 million annual revenue requirement related to KPCo’s investment in the Mitchell Plant. See “Mitchell Plant Filing for Certificate of Public Convenience and Necessity” section above for additional information. As part of this filing, KPCo requested a new generation rider to recover the remaining net book value of KPCo’s non-environmental investment in the Mitchell Plant that KPCo historically recovered through base rates. If the generation rider is approved, the $20 million would be removed from the requested revenue requirement increase and would be collected through the rider. Additionally, KPCo is pursuing securitization legislation that would allow KPCo to securitize the remaining net book value of the Mitchell Plant. If the securitization of the remaining Mitchell Plant net book value is successful, collection of costs through the generation rider would cease.

In January 2026, KPCo and certain intervening parties submitted a settlement agreement with the KPSC proposing a $77 million annual increase in Kentucky retail rates, including: (a) a $59 million annual increase in KPCo base rates based on a

9.8% authorized ROE and a capital structure of 53.9% debt and 46.1% common equity, and (b) a new generation rider with a first year revenue requirement of $18 million based on a 9.7% authorized ROE to recover non-environmental plant investments at Mitchell Plant and all incremental capital investments after May 31, 2025 at both Mitchell Plant and Big Sandy Plant. Capital and other operation and maintenance expenses related to any new generating assets also will be eligible for inclusion in the Generation Rider, subject to KPSC approval. The settlement revenue requirement will be reduced by $25 million in the first year and $15 million in the second year through a new rider that returns certain unprotected deferred tax expenses in customer rates on a temporary basis, and then beginning in the third year, collects the deferred tax expense amounts from customers over the estimated time period that taxes are due to the IRS. The settlement agreement also proposes: (a) approval to defer all storm other operation and maintenance expenses above or below the level included in base rates, and (b) approval to defer vegetation management costs above or below the level included in base rates, capped at a total of $45 million in 2026 and $52 million in 2027. Consistent with the KPSC order in KPCo’s 2023 Kentucky Base Rate Case filing, the settlement agreement also provides that KPCo’s proposal to include a stand-alone NOLC deferred tax asset in rate base will be addressed in a future proceeding upon KPCo’s receipt of a PLR or other guidance from the IRS. A hearing was held in January 2026.

In February 2026, the KPSC issued an order modifying the January 2026 settlement agreement and approving an annual increase of $55 million in Kentucky retail rates based upon a 9.75% base rate ROE effective March 1, 2026. This increase is inclusive of a $36 million increase in base rates and a $19 million increase due to the new generation rider. The order reduced the settlement revenue requirement by $22 million primarily due to a $10 million reduction related to FERC transmission expense and a $9 million reduction in incentive and other compensation. Additionally, the KPSC ordered that $47 million of certain vegetation management costs previously incurred and capitalized from January 2018 through May 2025 should be reclassified as a regulatory asset to be recovered over a 30 year period with no carrying costs, and that prospective vegetation management costs incurred should no longer be capitalized but instead be treated as operating expense.

In March 2026, KPCo filed a request with the KPSC seeking rehearing on the vegetation management finding in the base case order in addition to certain other denied costs. In April 2026, the KPSC issued an order approving KPCo’s request for rehearing and set a procedural schedule for submitting information requests. Additionally, the order authorized KPCo to defer $17 million of certain vegetation management costs previously incurred and capitalized from June 2025 through February 2026 to a regulatory asset, pending the KPSC’s final decision on rehearing. If any costs included in the request for rehearing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters (Applies to AEP and OPCo)

OVEC Cost Recovery Audits

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

In August 2024, the PUCO issued orders pertaining to the OVEC cost recovery audits that: (a) denied intervenors’ application for rehearing on the 2016-2017 audit period, (b) determined costs incurred by OPCo during the 2018-2019 audit period were prudent, (c) determined costs incurred by OPCo during the 2020 audit period were prudent and (d) recommended no disallowances for any mentioned audit period in question. In September 2024, intervenors filed for rehearing on the 2018-2019 and 2020 OVEC cost recovery audit periods claiming the PUCO’s August 2024 orders to adopt the findings of the audit reports were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In October 2024, the PUCO denied the intervenors’ applications for rehearing of the 2018-2019 and 2020 audit periods. In December 2024, intervenors filed appeals with the Supreme Court of Ohio on the PUCO’s denial for rehearing. In April 2026, the Supreme Court of Ohio issued a decision affirming the PUCO’s August 2024 order which determined costs incurred by OPCo during the 2018-2019 audit period were prudent.

In February and March 2025, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2021-2023 audit period were imprudent and should be disallowed. Management disagrees with these claims and is unable to predict the impact of these disputes. An evidentiary hearing was held in November 2025 and post-hearing briefs were submitted in February 2026. If any costs are disallowed or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

2025 Ohio Base Rate Case

In May 2025, OPCo filed a request with the PUCO for a net $97 million annual increase in distribution base rates based upon a 10.9% ROE and a proposed capital structure of 49.1% debt and 50.9% common equity.

In January 2026, OPCo, the PUCO staff, and certain intervenors filed a settlement agreement with the PUCO. After incorporating reductions to rider rates, the settlement reflects an annual net revenue increase of $11 million based upon a 9.84% ROE and a capital structure of 49.1% debt and 50.9% common equity while also securing a reduction in customer rates through the amortization of $82 million of deferred tax regulatory liabilities over 18 months, an item not included in the original application. The resulting overall annual revenue impact is a net decrease of $59 million. The difference between OPCo’s requested annual base rate increase and the settlement is primarily due to a reduction in the requested ROE. Additionally, the agreement proposed increased revenue caps for the Distribution Investment Rider, annual cost cap increases in the Enhanced Service Reliability Rider and would result in no material disallowances. In April 2026, the PUCO issued an order approving the joint stipulation and settlement agreement and rates went into effect. In May 2026, two intervenors filed applications for rehearing.

March 2026 Storm Costs

In March 2026, the service territory of OPCo was impacted by strong winds from an isolated storm resulting in power outages and damage to the transmission and distribution infrastructure. As of March 31, 2026, OPCo had incurred approximately $20 million in incremental operation and maintenance costs related to service restoration efforts. The incremental storm restoration costs have been deferred as a regulatory asset and OPCo expects to seek future recovery of those costs through its approved storm cost recovery mechanism.

PSO Rate Matters (Applies to AEP and PSO)

2026 Oklahoma Base Rate Case

In January 2026, PSO filed a request with the OCC for a $299 million annual base rate increase based upon a 10.5% ROE with a capital structure of 50.1% debt and 49.9% common equity, net of existing rider revenue and certain incremental renewable facility benefits expected to be provided to customers through riders. PSO also requested an expanded transmission cost recovery rider and a new vegetation management rider. Further, PSO is seeking approval of new large load special terms and conditions in the Large Power and Light tariff.

In May 2026, various intervenors and staff filed testimony supporting an annual base rate increase ranging from $10 million to $109 million based on a recommended ROE ranging from 8.3% to 9.38%. The primary differences between PSO’s requested annual increase in base rates and staff and intervenors’ recommendations include: (a) a reduction in the proposed ROE, (b) modifications to PSO’s previously approved treatment of a stand-alone NOLC deferred tax asset in rate base, (c) treatment of storm costs and (d) adjustments to PSO's proposed depreciation and amortization.

If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2025 Texas Base Rate Case

In October 2025, SWEPCo filed a request with the PUCT for a $164 million annual increase in Texas base rates based upon a 10.75% ROE and a proposed capital structure of 48% debt and 52% common equity. The request would move certain revenues recovered through riders, including interim revenues on transmission and distribution investment since the 2020 Texas Base Rate Case, into base rates resulting in a net annual rate increase of $95 million. The proposed net annual increase includes recovery of the Texas jurisdictional share of the retired Pirkey Plant through depreciation expense and requests $21 million annually to recover deferred storm costs and expand the utility’s self-insurance reserve for potential losses and damages.

In March 2026, various intervenors filed testimony supporting a reduction to SWEPCo's net request ranging from $36 million to $64 million based on a recommended ROE ranging from 9.25% to 9.44%. In March 2026, PUCT staff filed testimony supporting a reduction to SWEPCo's net request of $26 million based on an ROE of 9.6%. The primary differences between SWEPCo’s requested annual increase in base rates and staff and intervenors’ recommendations include: (a) recovery of Pirkey Plant, (b) modifications to SWEPCo’s previously approved treatment of a stand-alone NOLC deferred tax asset in rate base and (c) a reduction in the proposed ROE.

In April 2026, a unanimous settlement in principle was reached and SWEPCo filed a motion to abate the hearing. A PUCT order on the settlement is not expected until the fourth quarter of 2026.

If the PUCT does not accept the settlement and any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

PSO and SWEPCo Rate Matters (Applies to AEP, PSO and SWEPCo)

North Central Wind Energy Facilities (NCWF)

The NCWF are subject to various regulatory performance requirements, including a Net Capacity Factor (NCF) guarantee. The NCF guarantee measures in MWhs across all facilities on a combined basis for each five year period for the first thirty full years of operation. The first NCF guarantee five year period began in April 2022. Certain wind turbines experienced performance issues that prompted PSO and SWEPCo to file a lawsuit against the manufacturer, which led to an agreement between PSO and SWEPCo and the manufacturer that addressed the performance issues. If regulatory performance requirements, such as the NCF guarantee, are not met, PSO and SWEPCo may recognize a regulatory liability associated with a refund to retail customers.

FERC Rate Matters

Independence Energy Connection Project (Applies to AEP)

In 2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan to alleviate congestion. Transource Energy has an ownership interest in the IEC, which is located in Maryland and Pennsylvania. In June 2020, the Maryland Public Service Commission approved a CPCN to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PAPUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy appealed the PAPUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. In May 2022, the Pennsylvania state court issued an order affirming the PAPUC decision as to state law claims. In December 2023, the United States District Court for the Middle District of Pennsylvania granted summary judgment in favor of Transource Energy, finding that the PAPUC decision violated federal law and the United States Constitution. In January 2024, the PAPUC filed an appeal of the district court’s grant of summary judgment with the United States Court of Appeals for the Third Circuit. In September 2025, the United States Court of Appeals for the Third Circuit affirmed the December 2023 district court order in favor of Transource Energy. The Pennsylvania Attorney General subsequently petitioned to intervene, which the United States Court of Appeals for the Third Circuit denied. The Pennsylvania Attorney General sought review of the United States Court of Appeals for the Third Circuit’s denial at the United States Supreme Court, which is pending.

In October 2025, the Maryland Public Service Commission approved an extension of the construction commencement deadline to May 2026. Additional regulatory proceedings before the PAPUC are expected to resume in 2026.

In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC had not been canceled and remained necessary to alleviate congestion. In July 2025, PJM removed the IEC from suspended status and indicated the project going forward will be included in PJM’s models with a modified scope. PJM continues to evaluate reliability and market efficiency in the area. As of March 31, 2026, AEP’s share of IEC capital expenditures was approximately $96 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is canceled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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

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

In January 2024, the FERC issuedtwo orders granting formal challenges by certain unaffiliated customers related to stand-alone treatment of NOLCs in the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP. The FERC directed the AEP transmission owning subsidiaries within PJM and SPP to provide refunds with interest on all amounts collected for the 2021 rate year, and for such refunds to be reflected in the annual update for the next rate year. Accordingly, AEP transmission owning subsidiaries within PJM and SPP provided refunds for the 2021 rate year, primarily through 2025 transmission revenue requirements. AEP transmission owning subsidiaries within PJM and SPP have not been directed to make cash refunds related to 2022 through 2025 rate years. As a result of the January 2024 FERC orders, the Registrants’ balance sheets reflected a liability for the probable refund of all NOLC revenues included in transmission formula rates, with interest.

In February 2024, AEPSC on behalf of the AEP transmission owning subsidiaries within PJM and SPP filed requests for rehearing. In March 2024, the FERC denied AEPSC’s requests for rehearing of the January 2024 orders by operation of law and stated it may address the requests for rehearing in future orders. In March 2024, AEPSC submitted refund compliance reports to the FERC, which preserve the non-finality of the FERC’s January 2024 orders pending further proceedings on rehearing and appeal. In April 2024, AEPSC made filings with the FERC which requested that the FERC: (a) reopen the record so that the FERC may take the IRS PLRs received in April 2024 regarding the treatment of stand-alone NOLCs in ratemaking into evidence and consider them in substantive orders on rehearing and (b) stay its January 2024 orders and related compliance filings and refunds to provide time for consideration of the April 2024 IRS PLRs. In May 2024, AEPSC filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit seeking review of the FERC’s January 2024 and March 2024 decisions. In July 2024, the FERC issued orders approving AEPSC’s request to reopen the record for the limited purpose of accepting into the record the IRS PLRs and establish additional briefing procedures. In August 2024, AEPSC filed briefs with the FERC requesting the commission modify or overturn its initial orders.

In June 2025, the FERC issuedtwo 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. Requests for rehearing were filed by intervenors in July 2025 and were rejected by FERC on the merits in November 2025. In March 2026, an intervenor filed a formal challenge and complaint regarding the NOLC adjustments in the 2025 annual update covering the transmission formula rates for 2024 in PJM. Intervenors have filed petitions for review of the FERC’s orders in this matter with the United States Court of Appeals for the District of Columbia Circuit. The appeals have been consolidated and are pending the establishment of a procedural schedule.

As directed by the FERC in its June 2025 order, AEP transmission owning subsidiaries within PJM and SPP submitted compliance filings in August 2025 that revised the March 2024 refund compliance reports and permit the collection of excess refunds provided to customers, with interest, in the annual update for the 2025 rate year. In October 2025, intervenors filed comments in response to the compliance filings. In March and April 2026, the FERC approved the AEP transmission owning subsidiaries’ compliance filings related to PJM and SPP, respectively.

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

Transmission Agreement Cost Allocation Complaint (Applies to AEP, APCo, I&M and OPCo)

In March 2025, the KPSC and the Attorney General of Kentucky filed a complaint at the FERC against AEPSC and the AEP East Companies challenging the manner in which costs are allocated for local transmission projects pursuant to the TA. The complaint contends that certain costs allocated to KPCo are unjust, unreasonable and provide no benefit to KPCo customers. The relief requested in the complaint includes requiring a revision to the TA so that the costs for local transmission projects remain exclusively with the retail distribution service territory where the project is located unless a specific project is granted approval to establish a different cost allocation by the state commissions. Various parties have filed comments and motions to intervene. In May 2025, AEP filed a motion to dismiss and answered the complaint. In November 2025, the FERC issued an order denying the KPSC and Attorney General of Kentucky complaint. In December 2025, the KPSC and Attorney General of Kentucky requested a rehearing of the November order denying the complaint. In January 2026, the FERC issued a notice of denial of the request for rehearing by operation of law, providing the FERC with additional time to consider and decide on the merits of the request. In February 2026, the KPSC and Attorney General of Kentucky filed a petition for review of the FERC’s orders in this matter with the United States Court of Appeals for the Sixth Circuit. In March 2026, the FERC again denied the complaint, continuing to find that the KPSC and Attorney General of Kentucky have not met their burden of proof. If the FERC orders a change in the way costs are allocated pursuant to the TA it could impact future net income, cash flows and financial condition.

FERC Audit (Applies to all Registrant Subsidiaries)

The FERC Division of Audits and Accounting initiated an audit of SWEPCo in April 2024 evaluating certain accounting and reporting requirements under various FERC regulations, including compliance with the approved terms, rates and conditions of its SPP transmission formula rate mechanism. In March 2026, the FERC issued a final audit report which included, among other things, findings and recommendations related to SWEPCo's policy for the capitalization of certain vegetation management costs.

As a result of the final audit report, effective starting the first quarter of 2026, AEP will no longer capitalize the vegetation management costs identified in the FERC finding on a prospective basis. AEP's PJM and SPP transmission formula rates will provide recovery of these costs as an expense effective with the 2026 rate year. Retail ratemaking for these costs will be determined in current or future ratemaking proceedings in each jurisdiction which may allow the continued capitalization of these costs as property, plant and equipment or deferral as regulatory assets. Management is unable to predict the outcome in any current or future ratemaking proceeding. If any refund liabilities are imposed by any retail commission or any disallowances occur, it would reduce future net income and cash flows and impact financial condition.

Further discussions with the FERC audit staff will be held in 2026 to finalize the resolution of all findings noted in the final audit report. If any refund liabilities are imposed by the FERC or any disallowances occur, it would reduce future net income and cash flows and impact financial condition for SWEPCo.

5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2025 Annual Report should be read in conjunction with this report.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third-parties unless specified below.

Letters of Credit (Applies to AEP)

Standby letters of credit are entered into with third-parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

In April 2026, AEP increased its $5 billion revolving credit facility to $6.5 billion and extended the due date from March 2029 to April 2031. Also, in April 2026, AEP increased its $1 billion revolving credit facility to $1.5 billion and extended the due date from March 2027 to April 2029. AEP may issue up to $1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of March 31, 2026, no letters of credit were issued under either revolving credit facility.

An uncommitted facility gives AEP the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries undersix uncommitted facilities totaling $450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 2026 were as follows:

Indemnifications and Other Guarantees

Contracts

The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2026, there were no material liabilities recorded for any indemnifications.

AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf. AEPSC also conducts power purchase-and-sale activity on behalf of PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf.

Master Lease Agreements (Applies to all Registrants except AEPTCo)

The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed. As of March 31, 2026, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

Federal EPA’s Revised CCR Rule

In April 2024, the Federal EPA finalized revisions to the CCR Rule (Legacy CCR Rule) to expand the scope of the rule to include inactive impoundments at inactive facilities (legacy CCR surface impoundments) as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land (CCR management units). The Federal EPA is requiring that owners and operators of legacy surface impoundments comply with all of the Legacy CCR Rule requirements applicable to inactive CCR surface impoundments at active facilities, except for the location restrictions and liner design criteria. The rule establishes compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within five years after the effective date of the final rule. The rule requires evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. Closure may be accomplished by applying an impermeable cover system over the CCR material (closure in place) or the CCR material may be excavated and placed in a compliant landfill (closure by removal). Groundwater monitoring and other analysis over the next three years will provide additional information on the planned closure method. In the second quarter of 2024, AEP evaluated the applicability of the rule to current and former plant sites and recorded a $674 million increase in ARO, based on initial cost estimates primarily reflecting compliance with the rule through closure in place and future groundwater monitoring requirements pursuant to the Legacy CCR Rule.

As further groundwater monitoring and other analysis is performed, management expects to refine the assumptions and underlying cost estimates used in recording the ARO. These refinements may include, but are not limited to, changes in the expected method of closure, changes in estimated quantities of CCR at each site, the identification of new CCR management units, among other items. These future changes could have a material impact on the ARO and materially reduce future net income and cash flows and further impact financial condition.

In November 2025, the Federal EPA proposed to extend bythree years the compliance deadline applicable to certain facilities operating pursuant to alternative closure deadlines for unlined surface impoundments greater than 40 acres.

In January 2026, APCo received a final order from the Virginia SCC approving the recovery of $80 million of Legacy CCR Rule regulatory assets through 2041 and concurrent recovery of ongoing depreciation and accretion expenses. AEP will continue to seek cost recovery through regulated rates in other jurisdictions, including proposal of new regulatory mechanisms for cost recovery where existing mechanisms are not applicable. The rule could have an additional, material adverse impact on net income, cash flows and financial condition if AEP cannot ultimately recover these additional costs of compliance. Several parties, including AEP and one of its trade associations, have filed petitions for review of the Legacy CCR Rule with the U.S. Court of Appeals for the District of Columbia Circuit. The litigation is being held in abeyance. 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. Management cannot predict the outcome of the litigation.

In April 2026, the Federal EPA proposed revisions to the CCR Rule that would rescind requirements for CCR management units, revise requirements for beneficial use of CCR materials, allow expanded reliance on state-approved and other regulatory closures of legacy units, and introduce a new, permit-based, site-specific compliance pathway. The proposal is expected to be finalized by the end of 2026. Management is evaluating the proposal and intends to participate in the rulemaking process through submission of comments, but cannot predict the outcome of the rulemaking process.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials. The Registrants currently incur costs to dispose of these substances safely. For remediation processes not specifically discussed, management does not anticipate that the liabilities, if any, arising from such remediation processes would have a material effect on the financial statements.

NUCLEAR CONTINGENCIES (Applies to AEP and I&M)

I&M owns and operates the Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate thetwo nuclear units at the Cook Plant expire in 2034 and 2037. Management has started the application process for license extensions for both units that would extend Unit 1 and Unit 2 to 2054 and 2057, respectively. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cybersecurity incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third-parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers.

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cybersecurity incident, extreme weather, wildfire related liabilities or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered through the ratemaking process, could reduce future net income and cash flows and impact financial condition.

Claims for Indemnification Made by Owners of the Gavin Power Station (Applies to AEP)

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 Environmental Protection Agency and to indemnify the purchasers for that work. In July 2021, closure work was completed by AEP. In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow another pond at the Gavin Power Station, the CCR surface impoundment, to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several assertions related to the CCR Rule, 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, including any future enforcement or litigation resulting from any determinations of noncompliance by the Federal EPA with various aspects of the CCR Rule consistent with the Gavin Denial. The owners of the Gavin Power Station have also sought indemnification for landowner claims for property damage allegedly caused by modifications to the FAR. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the

PSA. In January 2024, Gavin Power LLC filed a complaint with the United States District Court for the Southern District of Ohio, alleging various violations of the Administrative Procedure Act and asserting that the Federal EPA, through its prior inaction, has waived and is estopped from raising certain objections raised in the Gavin Denial. The complaint does not assert any claims against AEP. In August 2025, the District Court granted the Federal EPA’s Motion to Dismiss the complaint and the Court dismissed the case in December 2025. Based on the information currently available, management does not believe a loss is probable and cannot determine a range of potential losses, if any, that is reasonably possible of occurring.

6. ACQUISITIONS AND IMPAIRMENTS

The disclosures in this note apply to AEP unless indicated otherwise.

ACQUISITIONS

Oregon Clean Energy Center (Applies to AEP and I&M)

In March 2026, I&M completed the acquisition of 100% of the equity interests in Oregon Clean Energy, LLC, the owner of the Oregon Clean Energy Center (Oregon Plant), a natural gas powered, combined-cycle electric generation facility located in Oregon, Ohio. The Oregon Plant began commercial operations in 2017. I&M acquired the Oregon Plant to provide capacity and energy to both I&M Indiana and FERC jurisdictional customers. As approved by the IURC in November 2025 and prior to incorporation into the development of Indiana base rates, I&M will initially reflect costs associated with the Oregon Plant either as eligible costs for recovery through existing I&M Indiana riders or in I&M’s ongoing Indiana earnings test evaluation.

In accordance with the guidance for “Business Combinations,” management determined the acquisition of the Oregon Plant represents an asset acquisition. Asset acquisition is accounted for using a cost accumulation model with the cost of the acquisition allocated to the acquired assets and assumed liabilities based on their relative fair value. The table below summarizes the impact at acquisition on I&M’s balance sheets:

IMPAIRMENTS

2025 Texas Base Rate Case (Applies to AEP and SWEPCo)

During the first quarter of 2026, SWEPCo recorded a pretax disallowance of $31 million in Asset Impairments and Other Related Charges on the statements of income due to a probable partial regulatory disallowance of recovery of the Pirkey Plant net book value in the 2025 Texas Base Rate Case. See the “2025 Texas Base Rate Case” section of Note 4 for additional information.

7. BENEFIT PLANS

The disclosures in this note apply to all Registrants except AEPTCo.

AEPSC sponsors a qualified pension plan andtwo unfunded non-qualified pension plans. Substantially all AEP subsidiary employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. AEPSC also sponsors OPEB plans to provide health and life insurance benefits for retired employees.

Components of Net Periodic Benefit Cost (Credit)

Pension Plans

OPEB

8. BUSINESS SEGMENTS

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.

The CODM of AEP is the President and CEO of AEP, whomakes operating decisions, allocates resources to and assesses performance based on these reportable segments. The CODM uses earnings (loss) attributable to AEP common shareholders (presented on a GAAP basis) as a measure of segment profit or loss in making these decisions. Earnings (loss) attributable to AEP common shareholders includes intercompany revenues and expenses that are eliminated on the consolidated financial statements.

AEP’s reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

•Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

•Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.

•OPCo purchases energy and capacity to serve standard service offer customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

•Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved ROEs.

•Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ROEs.

Generation & Marketing

•Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP.

•Competitive generation in PJM.

The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, income tax expense and other nonallocated costs.

The tables below represent AEP’s reportable segment income statement information for the three months ended March 31, 2026 and 2025 and reportable segment balance sheet information as of March 31, 2026 and December 31, 2025. The significant expenses disclosed below align with the segment-level information that is regularly provided to the CODM.

(a)Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, income tax expense and other nonallocated costs.

(b)Represents inter-segment revenues.

(c)Other segment items included in segment earnings (loss) attributable to AEP common shareholders primarily includes Interest and Dividend Income, Non-Service Cost Components of Net Periodic Benefit Cost and Net Income (Loss) Attributable to Noncontrolling Interests.

(d)Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.

(e)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.

Registrant Subsidiaries’ Reportable Segments (Applies to all Registrant Subsidiaries except AEPTCo)

The Registrant Subsidiaries each haveone reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an integrated electricity transmission and distribution business for AEP Texas and OPCo. Other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. The CODM of each Registrant Subsidiary is the AEP President and CEO, who makes operating decisions, allocates resources to and assesses performance based on these reportable segments. The CODM uses earnings (loss) attributable to common shareholders and net income (loss) that is reported on the Registrant Subsidiaries’ statements of income as a measure of segment profit or loss in making these decisions. Earnings (loss) attributable to common shareholders and net income (loss) include intercompany revenues and expenses that are eliminated on the consolidated financial statements. The expenses disclosed on the Registrant Subsidiaries’ statements of income align with the segment-level significant expenses that are regularly provided to the CODM. Total Assets is reported on the consolidated financial statements. Gross Property Additions for the Registrant Subsidiaries is represented by the sum of Construction Expenditures and Acquisition of Assets on the consolidated financial statements. See Registrant Subsidiaries statements of income, balance sheets and cash flows for details.

AEPTCo’s Reportable Segments

AEPTCo Parent is the holding company ofseven FERC-regulated transmission-only electric utilities. Theseven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos’ business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for ratemaking purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems.

The CODM of AEPTCo is the AEP President and CEO, who makes operating decisions, allocates resources to and assesses performance based on these operating segments. The CODM uses earnings (loss) attributable to AEPTCo common shareholders (presented on a GAAP basis) as a measure of segment profit or loss in making these decisions. Earnings (loss) attributable to AEPTCo common shareholders includes intercompany revenues and expenses that are eliminated on the consolidated financial statements. The State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated intoone reportable segment. As a result, AEPTCo hasone reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities.

The tables below present AEPTCo’s reportable segment income statement information for the three months ended March 31, 2026 and 2025 and reportable segment balance sheet information as of March 31, 2026 and December 31, 2025. The significant expenses disclosed below align with the segment-level information that is regularly provided to the CODM.

(a)Elimination of intercompany interest income/interest expense on affiliated debt arrangement.

(b)Other segment items included in segment earnings (loss) attributable to AEPTCo common shareholders primarily includes Net Income (Loss) Attributable to Noncontrolling Interests.

(c)Includes elimination of AEPTCo Parent’s equity earnings in the State Transcos.

(d)Primarily relates to Notes Receivable from the State Transcos.

(e)Primarily relates to elimination of Notes Receivable from the State Transcos.

9. DERIVATIVES AND HEDGING

The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity.

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.

The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors of AEP.

The following table represents the gross notional volume of the Registrants’ outstanding derivative contracts:

Fair Value Hedging Strategies (Applies to AEP)

Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating-rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges.

Cash Flow Hedging Strategies

The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk.

The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $56 million and $83 million as of March 31, 2026 and December 31, 2025, respectively. The amount of cash collateral received from third-parties netted against short-term and long-term risk management assets was not material for the Registrant Subsidiaries as of March 31, 2026. There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of December 31, 2025. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was not material for the Registrants as of March 31, 2026 and December 31, 2025.

Location and Fair Value of Derivative Assets and Liabilities Recognized On the Balance Sheet

The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets. The derivative instruments are disclosed as gross. They are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” Unless shown as a separate line on the balance sheets due to materiality, Current Risk Management Assets are included in Prepayments and Other Current Assets, Long-term Risk Management Assets are included in Deferred Charges and Other Noncurrent Assets, Current Risk Management Liabilities are included in Other Current Liabilities and Long-term Risk Management Liabilities are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets.

Offsetting Assets and Liabilities

The following tables show the net amounts of assets and liabilities presented on the balance sheets. The gross amounts offset include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with accounting guidance for “Derivatives and Hedging.” All derivative contracts subject to a master netting arrangement or similar agreement are offset on the balance sheets.