AEP Transmission Company, LLC

•Retail Revenues increased $14 million primarily due to the following:

•A $16 million increase in rider revenues.

•An $11 million increase in weather-normalized revenues primarily in the commercial class.

•A $7 million decrease in weather-related usage primarily due to a 9% decrease in cooling degree days.

•Transmission Revenues increased $20 million primarily due to the following:

•A $21 million increase in transmission investments.

•Other Revenues increased $6 million primarily due to the taxable portion of payments received from customers for large interconnection projects.

•Other Operation and Maintenance expenses increased $26 million primarily due to the following:

•An $18 million increase due to the probable, partial disallowance of regulatory assets associated with the UTM deferrals.

•A $7 million increase due to recoverable Transmission Cost Recovery Factor expenses.

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

•Allowance for Equity Funds Used During Construction increased $8 million primarily due to a higher AFUDC base.

•Interest Expense increased $17 million primarily due to higher long-term debt balances.

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

•A $20 million decrease in weather-related usage primarily due to a 3% decrease in cooling degree days.

•A $7 million decrease due to Transition Funding customer refunds.

•A $14 million increase in weather-normalized revenues primarily in the residential and commercial classes.

•A $7 million increase in rider revenues.

•Transmission Revenues increased $33 million primarily due to the following:

•A $34 million increase in transmission investments.

•Other Revenues increased $15 million primarily due to the taxable portion of payments received from customers for large interconnection projects.

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

•Other Operation and Maintenance expenses increased $22 million primarily due to an $18 million increase due to the probable, partial disallowance of regulatory assets associated with the UTM deferrals.

•Depreciation and Amortization expenses increased $9 million primarily due to the following:

•An $18 million increase due to a higher depreciable base.

•A $7 million decrease primarily due to the amortization of regulatory liabilities related to Transition Funding customer refunds.

•A $3 million decrease due to the deferral of eligible costs related to the UTM.

•Allowance for Equity Funds Used During Construction increased $15 million primarily due to a higher AFUDC base.

•Interest Expense increased $10 million primarily due to the following:

•A $24 million increase due to higher long-term debt balances.

•An $8 million decrease due to an increase in the debt component of AFUDC.

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

•Income Tax Expense increased $6 million primarily due to the following:

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

•A $3 million increase due to an increase in pretax book income.

ASSETS

Summary of Investment in Transmission Assets for AEPTCo

•Transmission Revenues decreased $154 million primarily due to the following:

•A $60 million increase due to continued transmission investment.

•Other Operation and Maintenance expenses increased $11 million primarily due to an increase in employee-related costs, vegetation management expenses, affiliated rent expense and other miscellaneous expenses.

•Depreciation and Amortization expenses increased $9 million primarily due to a higher depreciable base.

•Taxes Other than Income Taxes increased $10 million primarily due to higher property taxes driven by higher transmission investments.

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

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

•Income Tax Expense increased $208 million primarily due to the following:

•A $39 million decrease due to a decrease in pretax book income.

•Net Income Attributable to Noncontrolling Interest decreased $30 million primarily due to following:

•A $24 million increase due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

•Transmission Revenues decreased $103 million primarily due to the following:

•A $111 million increase due to continued transmission investment.

•Operation and Maintenance expenses increased $28 million primarily due to an increase in employee-related costs, vegetation management expenses, affiliated rent expense and other miscellaneous expenses.

•Depreciation and Amortization expenses increased $23 million due to a higher depreciable base.

•Taxes Other than Income Taxes increased $24 million primarily due to higher property taxes driven by increased transmission investment.

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

•Interest Expense increased $17 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $207 million primarily due to the following:

•A $40 million decrease due to a decrease in pretax book income.

•Net Income Attributable to Noncontrolling Interest decreased $3 million primarily due to following:

•A $52 million increase 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 $40 million primarily due to the following:

•A $46 million decrease in fuel revenues.

•A $14 million decrease in weather-normalized revenues primarily in the residential and commercial classes.

•A $3 million decrease in weather-related usage due to a 30% decrease in heating degree days.

•A $32 million increase in base rate and rider revenues.

•Transmission Revenues increased $8 million primarily due to the following:

•A $13 million increase due to continued transmission investment.

•A $6 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $14 million primarily due to the following:

•A $32 million increase in under-recovered deferred fuel regulatory assets primarily driven by lower authorized fuel rates in Virginia.

•A $14 million prior year impact to the West Virginia ENEC as a result of the June 2025 FERC NOLC order.

•Other Operation and Maintenance expenses increased $12 million primarily due to the following:

•A $13 million increase in distribution expenses primarily due to storm-related expenses.

•A $5 million increase in steam generation expenses primarily due to increased plant maintenance.

•A $4 million increase in accretion expense related to AROs and the 2024 Legacy CCR Rule.

•A $3 million increase in administrative and general expenses primarily due to employee-related costs.

•A $15 million decrease in transmission expenses due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Depreciation and Amortization expenses decreased $7 million primarily due to a decrease in depreciation expense at Amos and Mountaineer plants due to the issuance of Virginia securitization bonds.

•Taxes Other Than Income Taxes increased $7 million primarily due to higher business and occupation taxes.

•Interest Expense increased $9 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $14 million primarily due to the following:

•A $23 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $9 million decrease due to a decrease in pretax book income.

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

•Retail Revenues decreased $56 million primarily due to the following:

•A $101 million decrease in fuel revenues.

•A $5 million decrease in weather-related usage primarily due to a 4% decrease in heating degree days.

•A $3 million decrease in weather-normalized revenues primarily in the residential and commercial classes.

•A $57 million increase in base rate and rider revenues.

•Transmission Revenues increased $22 million primarily due to the following:

•A $27 million increase due to continued transmission investment.

•A $6 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Other Revenues decreased $5 million primarily due to a decrease in sales of renewable energy credits.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $57 million primarily due to the following:

•A $73 million increase in the under-recovered deferred fuel regulatory assets primarily driven by lower authorized fuel rates in Virginia.

•A $14 million prior year impact to the West Virginia ENEC as a result of the June 2025 FERC NOLC order.

•Other Operation and Maintenance expenses increased $28 million primarily due to the following:

•A $27 million increase in distribution expenses primarily due to storm-related expenses.

•A $9 million increase in steam generation expenses primarily due to increased plant maintenance.

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

•A $5 million increase in accretion expense related to AROs and the 2024 Legacy CCR Rule.

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

•Depreciation and Amortization expenses decreased $2 million primarily due to the following:

•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.

•A $23 million increase 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.

•Taxes Other Than Income Taxes increased $13 million primarily due to the following:

•An $8 million increase due to higher business and occupation taxes.

•A $4 million increase in property taxes.

•Interest Expense increased $17 million primarily due to higher long-term debt balances.

•Income Tax Expense decreased $15 million primarily due to the following:

•An $18 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 $14 million decrease due to an increase in PTCs.

•A $9 million decrease due to a decrease in pretax book income.

•A $23 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

ASSETS

•Retail Revenues increased $121 million primarily due to the following:

•A $79 million increase in weather-normalized revenues primarily in the commercial class.

•A $47 million increase in fuel revenues.

•An $8 million increase in rider revenues.

•A $6 million increase due to a decrease in regulatory provisions for refund.

•An $8 million decrease in weather-related usage primarily due to a 21% decrease in cooling degree days.

•Off-system Sales decreased $38 million primarily due to Rockport Plant, Unit 2 merchant sales and economic hedging activity.

•Transmission Revenues decreased $16 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $20 million primarily due to an increase in recoverable fuel and purchased power costs, partially offset by a decrease in Rockport Plant, Unit 2, merchant generation fuel costs.

•Purchased Electricity from AEP Affiliates expenses decreased $8 million primarily due to a decrease in purchased electricity from AEGCo.

•Other Operation and Maintenance expenses increased $17 million primarily due to a $14 million increase in transmission expenses primarily due to an $8 million increase in recoverable PJM expenses and a $6 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Depreciation and Amortization increased $9 million primarily due to a higher depreciable base.

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

•Income Tax Expense increased $40 million primarily due to the following:

•A $32 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of stand-alone NOLCs in transmission formula rates.

•A $3 million increase due to an increase in pretax book income.

•A $3 million increase due to an increase in state taxes.

•A $3 million increase due to a decrease in PTCs.

•Retail Revenues increased $249 million primarily due to the following:

•A $134 million increase in weather-normalized margins primarily in the commercial class.

•A $65 million increase in fuel revenues.

•A $55 million increase in rider revenues.

•A $15 million increase due to a decrease in regulatory provisions for refund.

•A $10 million decrease in weather-related usage primarily due to a 20% decrease in cooling degree days.

•Off-system Sales increased $44 million primarily due to Rockport Plant, Unit 2 merchant sales during Winter Storm Fern in January 2026, partially offset by a decrease in merchant sales and economic hedging activity.

•Transmission Revenues decreased $13 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Other Revenues decreased $7 million primarily due to a decrease in River Transportation Division (RTD) barging revenues.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $76 million primarily due to an increase in recoverable fuel and purchased power costs, partially offset by a decrease in Rockport Plant, Unit 2, merchant generation fuel costs.

•Purchased Electricity from AEP Affiliates decreased $7 million primarily due to a decrease in purchased electricity from AEGCo.

•Other Operation and Maintenance expenses increased $50 million primarily due to the following:

•A $26 million increase in transmission expenses primarily due to a $17 million increase in recoverable PJM expenses and a $6 million increase due to the June 2025 FERC order related to the treatment of stand-alone NOLCs in transmission formula rates.

•A $7 million increase in distribution expenses primarily due to an increase in vegetation management costs and other distribution-related expenses.

•A $7 million increase in administrative and general expenses.

•A $6 million increase in demand side management expenses.

•A $5 million increase in steam generation expenses primarily due to the acquisition of the Oregon Clean Energy Center in March 2026.

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

•A $5 million decrease in non-utility operation expenses due to a decrease in RTD barging expenses.

•Depreciation and Amortization expenses increased $16 million primarily due to the following:

•An $11 million increase due to a higher depreciable base.

•An $8 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 $6 million decrease due to Michigan PTC deferral activity.

•Other Income increased $7 million primarily due to an increase in AFUDC due to a higher AFUDC base and an increase in equity return rates.

•Interest Expense increased $18 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $59 million primarily due to the following:

•A $32 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of stand-alone NOLCs in transmission formula rates.

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

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 $90 million primarily due to the following:

•A $79 million increase in rider revenues.

•A $9 million increasedue to higher prices for purchased power to serve OPCo’s SSO customers.

•Off-system Sales decreased$7 million primarily due to decreased sales of OVEC purchased power driven bylower market prices.

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

•Purchased Electricity for Resale expenses decreased $17 million primarily due to the following:

•A $23 million decrease in OVEC purchased power costs.

•A $7 million increase in recoverable auction purchases to serve SSO customers.

•Other Operation and Maintenance expenses increased $90 million primarily due to the following:

•A $75 million increase primarily due to recoverable PJM transmission expenses.

•A $6 million increase primarily due to recoverable distribution vegetation management expenses.

•Taxes Other Than Income Taxes increased $28 million primarily due to the following:

•A $23 million increase in property taxes.

•A $5 million increase in state excise taxes due to increased billed KWhs.

•Income Tax Expense decreased $11 million primarily due to Excess ADIT credits refunded to customers as approved in the 2025 base rate case.

•Retail Revenues increased $142 million primarily due to the following:

•A $75 million increase in rider revenues.

•A $60 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.

•A $10 million increase in weather-normalized revenues primarily in the residential class.

•A $20 million decrease in weather-related usage driven by a 6% decrease in cooling degree days.

•Off-system Sales increased $18 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.

•Transmission Revenues increased $20 million primarily due to continued transmission investment.

•Other Revenues decreased $6 million primarily due to lower third-party Legacy Generation Resource Rider revenues related to the recovery of OVEC costs.

•Purchased Electricity for Resale expenses decreased $13 million primarily due to the following:

•A $44 million decrease as a result of legislation approved in Ohio in 2025 related to the elimination of OPCo’s ability to recover from customers, or refund to, the difference between purchased power expenses from OVEC.

•A $30 million decrease in OVEC purchased power costs.

•A $58 million increase in recoverable auction purchases to serve SSO customers.

•Purchased Electricity from AEP Affiliates expenses increased $5 million primarily due to an increase in recoverable purchases to serve SSO customers.

•Other Operation and Maintenance expenses increased $98 million primarily due to the following:

•A $65 million increase primarily due to a $50 million increase in recoverable PJM transmission expenses and an $11 million increase in recoverable transmission storm restoration costs and vegetation management expenses.

•A $15 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•A $14 million increase primarily due to recoverable distribution vegetation management expenses.

•Depreciation and Amortization expenses increased $13 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.

•Taxes Other Than Income Taxes increased $25 million primarily due to the following:

•An $18 million increase in property taxes.

•A $7 million increase in state excise taxes due to increased billed KWhs.

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

•A $22 million decrease due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 base rate case.

•A $10 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 $59 million primarily due to the following:

•A $64 million increase in rider revenues.

•A $12 million increase in weather-related usage primarily due to a 25% increase in cooling degree days.

•A $9 million decrease in weather-normalized revenues primarily in the residential class.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $8 million primarily due to a $17 million increase in recoverable PTCs partially offset by a $10 million decrease related to the impact on deferred fuel costs from decreased fuel revenues.

•Other Operation and Maintenance expenses increased $26 million primarily due to the following:

•A $15 million increase in generation expenses primarily due to acquisitions of generation facilities.

•A $9 million increase in employee-related costs.

•A $6 million increase in distribution expenses primarily due to overhead line maintenance.

•A $5 million decreasein transmission expenses primarily due to a $19 million decrease related to the June 2025 FERC NOLC order partially offset by a $13 million increase in SPP expenses.

•Depreciation and Amortization expenses increased $7 million primarily due to a higher depreciable base.

•Interest Expense increased $14 million primarily due to higher long-term debt balances.

•Retail Revenues increased $103 million primarily due to the following:

•A $126 million increase in rider revenues.

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

•A $17 million decrease in weather-normalized revenues primarily in the residential class.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $43 million primarily due to a $53 million increase in recoverable PTCs partially offset by a $10 million decrease primarily in purchased power prices.

•Other Operation and Maintenance expenses increased $63 million primarily due to the following:

•A $25 million increase in generation expenses primarily due to acquisitions of generation facilities.

•A $15 million increase intransmission expenses primarily due to a $30 million increase in SPP expenses partially offset by a $19 million decrease related to the June 2025 FERC NOLC order.

•An $11 million increase in distribution expenses primarily due to overhead line maintenance.

•An $11 million increase in employee-related costs.

•Depreciation and Amortization expenses increased $11 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $7 million primarily due to property taxes on acquired generation facilities.

•Interest Expense increased $27 million primarily due to the following:

•A $20 million increase due to higher long-term debt balances.

•A $3 million increase due to a prior year deferral of expenses as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.

•Income Tax Benefit increased $40 million primarilydue to the following:

•A $38 million increase due to an increase in PTCs.

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

•A $13 million decrease due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

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 $34 million increase in weather-normalized revenues in all classes.

•A $27 million increase in rider revenues across all jurisdictions.

•A $22 million increase due to the Arkansas base rate case.

•A $33 million decrease due to an $18 million decrease primarily as a result of lower authorized rates in Louisiana and a $15 million decrease in fuel revenue due to a refund of the Texas over-recovered fuel balance.

•A $23 million decrease due to a probable credit to certain existing wholesale generation customers.

•A $7 million decrease in weather-related usage primarily due to a 6% decrease in cooling degree days.

•Transmission Revenues decreased $8 million primarily due to the following:

•A $27 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $19 million increase due to continued transmission investment.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $36 million primarily due to the following:

•A $30 million decrease due to a decrease in the deferred fuel costs related to a $15 million Texas fuel refund and a $15 million decrease primarily due to lower authorized rates in Louisiana.

•An $8 million decrease primarily due to decreased purchased power prices and increased wind generation.

•A $7 million increase in recoverable PTCs.

•Other Operation and Maintenance expenses increased $25 million primarily due to the following:

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

•A $6 million increase in generation expenses primarily due to the acquisition of the Wagon Wheel Wind Facility.

•A $5 million increase due to the partial write-off of previously capitalized vegetation management costs as a result of SWEPCo’s FERC audit.

•Depreciation and Amortization expenses increased $15 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $6 million primarily due to an increase in property taxes.

•Interest Expense increased $25 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $14 million primarily due to the following:

•A $42 million decrease due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $24 million increase due to an increase in PTCs.

•Retail Revenues increased $42 million primarily due to the following:

•A $53 million increase in weather-normalized revenues in all classes.

•A $52 million increase in rider revenues across all jurisdictions.

•A $34 million increase due to the Arkansas base rate case.

•A $60 million decrease in fuel revenue due to a $43 million refund of the Texas over-recovered fuel balance and a $17 million decrease primarily due to lower authorized rates in Arkansas and Louisiana.

•A $23 million decrease due to a probable credit to certain existing wholesale generation customers.

•A $17 million decrease in weather-related usage primarily due to a 32% decrease in heating degree days.

•Transmission Revenues increased $11 million primarily due to the following:

•A $35 million increase due to continued transmission investment.

•A $27 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $56 million primarily dueto the following:

•A $55 million decrease due to a decrease in the deferred fuel costs related to a $43 million Texas fuel refund and a $12 million decrease primarily due to lower authorized rates in Arkansas and Louisiana.

•A $14 million decrease primarily due to decreased purchased power prices and increased wind generation.

•An $8 million decrease due to prior year Louisiana and Texas fuel disallowances.

•A $15 million increase in recoverable PTCs.

•A $12 million increase in non-recoverable fuel costs primarily in Louisiana.

•Other Operation and Maintenance expenses increased $57 million primarily due to the following:

•A $14 million increase in distribution expenses primarily due to overhead line maintenance.

•A $13 million increase in transmission expenses primarilydue to:

•A $23 million increase in SPP expenses.

•A $10 million decrease due to the June 2025 FERC order related to the treatment of NOLC's in transmission formula rates.

•A $12 million increase in generation expenses primarily due to the acquisition of the Wagon Wheel Wind Facility.

•A $6 million increase in employee-related costs.

•A $6 million increase due to the partial write-off of previously capitalized vegetation management costs as a result of SWEPCo’s FERC audit.

•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 $38 million primarily due to the following:

•A $30 million increase due to a higher depreciable base.

•A $7 million increase primarily due to higher over-recovery of costs and allowable returns associated with the generation rider.

•Taxes Other Than Income Taxes increased $8 million primarily due to an increase in property taxes.

•Allowance for Equity Funds Used During Construction increased $8 million primarily due to a higher AFUDC base.

•Interest Expense increased $36 million primarily due to the following:

•A $27 million increase due to higher long-term debt balances.

•A $7 million increase due to a prior year deferral of expenses as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.

•A $5 million increase related to the Texas tax normalization rider amortization.

•Income Tax Benefit increased $29 million primarily due to the following:

•A $56 million increase due to an increase in PTCs.

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

•A $42 million decrease due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

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 and six months ended June 30, 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 June 30, 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. In May 2026, the SEC formally proposed to rescind its climate-related disclosure rules. The proposal is subject to notice-and-comment rulemaking before a final rule can be approved.

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.

ASU 2026-02 “Environmental Credits and Environmental Credit Obligations” (ASU 2026-02)

In May 2026, the FASB issued ASU 2026-02, the intent of which is to improve the financial accounting for and disclosure of environmental credits and environmental credit obligations. The new standard establishes guidance on the recognition, measurement, presentation, and disclosure requirements for all public business entities that generate, purchase, or receive environmental credits or have a regulatory compliance obligation that may be settled with environmental credits.

The amendments in the new standard are effective for annual reporting periods beginning after December 15, 2027, and interim reporting periods within those annual reporting periods. Early adoption is permitted as of the beginning of an annual reporting period and should be applied on a retrospective basis. Management is currently evaluating the impact of this ASU on its consolidated financial statements and related disclosures.

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 June 30, 2026, SWEPCo’s share of the net investment in the Pirkey Plant was $171 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 the first quarter of 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 June 30, 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 June 30, 2026, the unrecovered value of these assets was $151 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. In July 2026, SWEPCo, PUCT staff and certain intervenors filed an unopposed stipulation and settlement agreement with the PUCT agreeing the application for a CCN should be approved. Additionally, in July 2026, SWEPCo and the LPSC staff filed a joint stipulation and term sheet with the LPSC agreeing the application for a CCN should be approved.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of June 30, 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 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.

(b)Includes ARO adjustment related to the revised CCR Rule to be addressed in future regulatory proceedings. See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

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

(d)In May 2026, APCo issued securitization bonds that included $141 million of storm operation and maintenance costs.

(a)Includes ARO adjustment related to the revised CCR Rule to be addressed in a future regulatory proceeding. See “Federal EPA’s Revised CCR Rule” section of Note 5 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)In May 2026, APCo issued securitization bonds that included $141 million of storm operation and maintenance costs. See “2025 Virginia Securitization Filing” section below for additional information.

(a)Includes ARO adjustment related to the revised CCR Rule to be addressed in a future regulatory proceeding. See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

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

(b)Includes ARO adjustment related to the revised CCR Rule to be addressed in a future regulatory proceeding. See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

(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 June 30, 2026, AEP Texas’ cumulative revenues from transmission and distribution interim base rate increases that are subject to review are estimated to be approximately $223 million. AEP Texas recognized an $8 million provision for refund related to the UTM filing for amounts collected through the second quarter of 2026. 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 which was based on an interpretation of a later effective date for eligible UTM deferrals. In April 2026, AEP Texas filed responses reflective of the legislative intent of Texas House Bill 5247 (2025). In May 2026, the PUCT Chairman issued a Commissioner Memorandum agreeing with the ALJ’s PFD and ordered the PUCT staff to complete a calculation to confirm the final disallowance amount. Completion of the Commission-required calculation and final order are expected in the third quarter of 2026. In conjunction with the Commissioner Memorandum, AEP Texas recognizedan unfavorable pretax impact of $23 million in May 2026 attributable to a portion of the deferrals included in the UTM application period.

As of June 30, 2026, AEP Texas had deferred approximately$72 millionof eligible costs as a regulatory asset of which $65 million will be included in AEP Texas’ next UTM application. Investments included in the UTM and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate case proceeding before the PUCT. If any of these deferred costs or investments 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.

2026 ENEC Update Filing

In April 2026, the Companies submitted their annual ENEC update filing with the WVPSC for the annual review period ended February 28, 2026, proposing a $21 million annual increase in ENEC rates when compared to existing ENEC rates. The Companies proposed that this increase in ENEC rates become effective September 1, 2026 with the increase in ENEC rates based on the Companies’ projected costs for period September 2026 through August 2027. The Companies’ ENEC update filing also included a projected August 31, 2026 ENEC under-recovery balance of $597 million ($285 million related to APCo). This projected ENEC under-recovery balance included recovery of final true-ups of the Companies’ West Virginia Modified Rate Base Cost (MRBC), Vegetation Management and Broadband surcharges as well as continued deferral of the Companies’ West Virginia base rate increase that was ordered by the WVPSC in August 2025 and February 2026. See “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” section below for further details. The Companies proposed that this projected August 31, 2026 ENEC under-recovery balance of $597 million be included in the final combined balance approved by the WVPSC for securitization in late 2026.

In June 2026, the Companies, Staff and intervening parties filed a settlement with the WVPSC which recommended a projected August 31, 2026 ENEC under-recovery balance of $594 million ($275 million related to APCo) to be eligible for securitization. The settlement further recommended that the ENEC annual review period ending February 28, 2026 remain open until the Companies’ next ENEC proceeding.

In July 2026, the WVPSC issued an order on the June 2026 settlement, approving a $593 million projected August 31, 2026 ENEC under-recovery balance ($274 million related to APCo) that will be included in the Companies’ overall balance to be securitized. The WVPSC’s order also approved an updated $2.7 billion overall balance to be securitized ($1.7 billion related to

APCo) as further described in the “2025 West Virginia Securitization Filing” section below. It is currently estimated that this securitization will take place in the fourth quarter of 2026.

For the Companies’ ongoing filing to determine updated ENEC rates effective September 1, 2026, an intervening party submitted testimony in July 2026 alleging that the Companies were imprudent in their coal procurement practices, but did not recommend a specific cost disallowance. It is anticipated that the WVPSC will issue an order on this ENEC update filing in the third quarter of 2026.

If any ENEC costs are not recoverable, it could 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 surcharge 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 carrying charges on revised MRBC under-recovery balances starting September 2024 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.

In May 2026, a group of APCo customers submitted an appeal to the West Virginia Intermediate Court of Appeals alleging that the WVPSC erred in its April 2026 order approving a final MRBC true-up without sufficient record support. This appeal was dismissed by the West Virginia Intermediate Court of Appeals for lack of jurisdiction. The group of APCo customers subsequently submitted the appeal to the West Virginia Supreme Court.

In July 2026, the WVPSC issued an order on the Companies’ June 2026 ENEC update filing, approving a $593 million projected August 31, 2026 ENEC under-recovery balance ($274 million related to APCo) that will be included in the Companies’ overall balance to be securitized. The WVPSC’s order approves the Companies’ proposed recovery of the remaining MRBC under-recovery balance of $34 million ($28 million related to APCo) as part of the $593 million ENEC under-recovery balance approved for securitization.

If any refund liabilities are imposed by the WVPSC related to MRBC, it could reduce future net income and cash flows and impact financial condition.

West Virginia Inflation-Based Rate Adjustment

In April 2026, the WVPSC issued an order conditionally approving an annual Inflation-Based Rate Adjustment to current base rates of 4% for residential and commercial customers and 2.5% for industrial customers, provided that the Companies: (a) agree with proceeding with securitization, unless otherwise ordered by the WVPSC, (b) agree that the April 2026 Notice of Intent to file a 2026 West Virginia base rate case will be withdrawn and (c) agree that a new base rate case will not be filed prior to June 1, 2027. In April 2026, the Companies agreed to the terms of the Inflation-Based Rate Adjustment described above and filed revised tariff sheets reflecting a $40 million combined annual increase to base rates effective July 1, 2026.

In May 2026, a group of APCo customers submitted an appeal to the West Virginia Intermediate Court of Appeals alleging that the WVPSC erred in its April 2026 order approving the Inflation-Based Rate Adjustment without adequate findings, evidentiary support or reasoned explanation demonstrating the approval of reasonable rates under WVPSC statutes. This appeal was dismissed by the West Virginia Intermediate Court of Appeals for lack of jurisdiction. The group of APCo customers subsequently submitted the appeal to the West Virginia Supreme Court.

In July 2026, an intervening party submitted an appeal to the West Virginia Supreme Court regarding the Inflation-Based Rate Adjustment alleging that the WVPSC: (a) failed to carry its burden of proving that the Companies’ existing rates were unreasonable and needed to be changed, (b) failed to adequately support its order with evidence of record and (c) violated the due process rights of the intervening party and the customers that it represents.

If the Companies are ordered to issue future refunds associated with the Inflation-Based Rate Adjustment, it would 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.

In July 2026, the WVPSC issued an order on the June 2026 settlement agreement in the Companies’ 2026 ENEC update filing, approving a modified $593 million projected August 31, 2026 ENEC under-recovery balance ($274 million related to APCo) and an overall securitization balance of $2.7 billion ($1.7 billion related to APCo) as reflected in the table below:

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

2025 Virginia Securitization Filing

In May 2026, APCo issued 20-year securitization bonds to finance approximately $1.4 billion of jurisdictional costs, including: (a) $1.2 billion of certain Virginia jurisdictional Property, Plant and Equipment balances for the Amos and Mountaineer Plants, (b) $141 million of Virginia jurisdictional major storm other operation and maintenance expenses deferred to Regulatory Assets during the 2024-2025 biennial period and (c) $11 million of up-front financing costs. After issuing the securitization bonds, APCo implemented a rider to recover annual securitization debt financing costs and the Base Rate Reduction (BRR) Rider to credit customers for the recovery of, and return on, the Amos and Mountaineer Plant costs currently included in APCo Virginia base rates.

2026 Virginia Base Rate Case

In May 2026, APCo filed a request with the Virginia SCC for a net $105 million annual decrease in distribution and generation base rates. Approximately $166 million of the proposed decrease to base rates is currently credited to customers through the BRR Rider associated with the securitization of certain Virginia jurisdictional Amos and Mountaineer Plant balances as described in the “2025 Virginia Securitization Filing” section above, resulting in an estimated net $61 million increase to base rates. The BRR Rider will expire upon the implementation of new base rates. The proposed $61 million annual increase in base rates is based on a 10.5% ROE and an actual capital structure of 50.3% debt and 49.7% common equity. The $61 million requested base rate increase is primarily due to general inflation, increased investment in distribution and generation, increased capital costs, and the costs of required programs to support electric vehicles and low-income solar. Intervenor testimony is due in August 2026 and staff testimony is due in September 2026. A hearing is scheduled for October 2026. The Virginia SCC’s final order is required to be issued no later than January 2027 with updated base rates to be implemented in March 2027. If any costs in this filing are not approved for recovery, 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 June 30, 2026, AEP’s share of ETT’s cumulative revenues from interim base rate increases that are subject to a prudency review is approximately $2 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.

In July 2026, following a unanimous settlement in principle among ETT, PUCT Staff and intervenors, the PUCT granted the parties' request to suspend the procedural schedule while the parties document the final settlement agreement. The proposed settlement is subject to approval by the PUCT, and the parties expect to file the agreement in the third quarter of 2026. ETT was granted authority to implement interim rates, subject to refund, effective August 1, 2026. If any of the costs in the case are not recoverable, 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 Inter-Company Power Agreement (ICPA) and the Rockport UPA with AEGCo ranging from $259 thousand to $14 million. In July 2026, the MPSC ordered a $1 million cost disallowance associated with the OVEC ICPA andno cost disallowance associated with the Rockport UPA with AEGCo.

In July 2025, the IURC issued an order on I&M’s Resource Adequacy Rider update filing approving I&M’s proposed capacity resource adjustments, including prospective recovery of OVEC capacity, energy and associated costs that were previously assigned to I&M Michigan retail customers starting with the June 2025-May 2026 PJM delivery year.

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. 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 June 2026, the IURC issued an order approving the jurisdictional cost allocation modifications and the $53 million over-earnings customer credit.

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 June 30, 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 $520 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. Additionally, the order authorized KPCo to defer $18 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. In July 2026, KPCo and intervenors filed rehearing briefs. KPCo’s filing also requested that the KPSC issue a rehearing order by September 1, 2026. 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 and June 2026, the Supreme Court of Ohio affirmed the PUCO’s August 2024 orders finding that costs incurred by OPCo during the 2018-2019 audit period and 2020 audit period, respectively, 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, the PUCO denied applications for rehearing submitted bytwo intervenors.

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 June 30, 2026, OPCo had incurred approximately $25 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.

In June 2026, PSO, OCC staff and certain intervening parties filed a non-unanimous partial joint stipulation and settlement agreement for a $73 million revenue increase based upon a 9.375% ROE utilizing PSO’s filed actual capital structure of 50.1% debt and 49.9% common equity that includes: (a) a requirement for PSO to provide a credit over atwo-year period for deferred tax liabilities related to tax repairs which will then be recovered over the life of the underlying plant after the credit period, (b) PSO to expand its SPP Transmission Cost Rider as requested, (c) no change in the treatment of PSO’s NOLC, and (d) PSO to recover vegetation management costs consistent with the amount in PSO’s filed request and defer $13 million of eligible vegetation management costs in the first year of implemented rates, and $4 million each year thereafter. All issues related to PSO's proposed large load tariffs would be an open issue at hearing. Certain intervening parties did not sign the settlement agreement and contested certain of its provisions. Interim rates were implemented on July 1, 2026 reflecting the terms of this settlement. A hearing was held and an order is expected in the third quarter of 2026. 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 expected in 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 decision at the United States Supreme Court, which was denied in June 2026.

In May 2026, the Maryland Public Service Commission approved an extension of the construction commencement deadline to June 2027. In May 2026, Transource Energy filed its siting application for a CPCN to provide utility service in Franklin County, Pennsylvania, a petition for exemption from certain local zoning regulations, and a motion to consolidate thethree filings.

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 June 30, 2026, AEP’s share of IEC capital expenditures was approximately $97 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: