AEP Texas Inc.

•Retail Revenues increased $38 million primarily due to the following:

•A $27 million increase in rider revenues.

•A $14 million increase in weather-related usage primarily due to an 18% increase in cooling degree days.

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

•Other Revenues decreased $5 million primarily due to a reduction in the PUCT authorized cap on Texas energy efficiency utility incentives.

Expenses and Other changed between years as follows:

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

•A $14 million increase in transmission and distribution expenses.

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

•Depreciation and Amortization expenses increased $10 million primarily due to a higher depreciable base.

•Allowance for Equity Funds Used During Construction increased $10 million primarily due to a higher AFUDC base.

•Interest Expense increased $13 million primarily due to the following:

•A $14 million increase due to higher long-term debt balances.

•A $10 million increase due to interest on customer deposits from ERCOT’s Batch Zero process.

•A $6 million decrease due to an increase in the debt component of AFUDC.

•A $5 million decrease due to the deferral of eligible costs related to the UTM.

•Retail Revenues increased $31 million primarily due to the following:

•A $34 million increase in rider revenues.

•A $13 million increase in weather-normalized revenues primarily in the residential and commercial classes.

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

•A $6 million decrease in weather-related usage due to less extreme weather conditions in the first six months of 2026 compared to the same period in 2025.

•Transmission Revenues increased $40 million primarily due to continued transmission investment.

•Other Revenues increased $10 million primarily due to the following:

• A $16 million increase in the taxable portion of payments received from customers for large interconnection projects.

•A $7 million decrease primarily due to a reduction in the PUCT authorized cap on Texas energy efficiency utility incentives.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $46 million primarily due to the following:

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

•A $14 million increase in transmission and distribution expenses.

•A $13 million increase in administrative and general expenses primarily due to employee-related expenses.

•Depreciation and Amortization expenses increased $19 million primarily due to the following:

•A $27 million increase due to a higher depreciable base.

•A $5 million decrease primarily due to the amortization of regulatory liabilities related to Transition Funding customer refunds.

•A $4 million decrease due to the deferral of eligible costs related to the UTM.

•Allowance for Equity Funds Used During Construction increased $25 million primarily due to a higher AFUDC base.

•Interest Expense increased $23 million primarily due to the following:

•A $38 million increase due to higher long-term debt balances.

•A $10 million increase due to interest on customer deposits from ERCOT’s Batch Zero process.

•A $15 million decrease due to an increase in the debt component of AFUDC.

•An $11 million decrease due to the deferral of eligible costs related to the UTM.

ASSETS

Summary of Investment in Transmission Assets for AEPTCo

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

•Transmission Revenues increased $36 million primarily due to continued transmission investment.

•Other Operation and Maintenance expenses increased $9 million primarily due to the following:

•A $7 million increase in employee-related costs.

•A $2 million increase in affiliated rent and shared services.

•A $2 million increase in vegetation management and facility compliance costs.

•Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base.

•Taxes Other than Income Taxes decreased $10 million primarily due to prior period adjustments in Ohio, partially offset by higher property taxes associated with increased transmission investment.

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

•Interest Expense increased $6 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $5 million primarily due to an increase in pretax book income.

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

•Transmission Revenues decreased $67 million primarily due to the following:

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

•A $147 million increase due to continued transmission investment.

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

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

•A $16 million increase in employee-related costs.

•A $12 million increase in vegetation management and facility compliance costs.

•A $7 million increase in affiliated rent and shared services.

•Depreciation and Amortization expenses increased $35 million due to a higher depreciable base.

•Taxes Other than Income Taxes increased $14 million primarily due to higher property taxes associated with increased transmission investment, partially offset by prior period adjustments in Ohio.

•Allowance for Equity Funds Used During Construction increased $10 million primarily due to a higher CWIP base and higher equity rates.

•Interest Expense increased $23 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $212 million primarily due to the following:

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

•A $34 million decrease due to a decrease in pretax book income.

•A $5 million decrease due to a decrease in state taxes.

•Net Income Attributable to Noncontrolling Interest increased $1 million primarily due to the following:

•A $55 million increase due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

•A $54 million decrease due to higher 2025 earnings for Midwest Transmission Holdings due to the impact of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

ASSETS

LIABILITIES AND MEMBER’S EQUITY

•Retail Revenues increased $53 million primarily due to the following:

•A $53 million increase in base rate and rider revenues.

•A $21 million increase in weather-related usage due to a 25% increase in cooling degree days.

•A $13 million decrease in fuel revenues.

•Off-system Sales increased $7 million primarily due to margins in July 2026 attributable to increased PJM prices.

•Transmission Revenues increased $10 million primarily due to continued transmission investment.

•Other Revenues increased $6 million due to an increase in sales of renewable energy credits.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $24 million primarily due to the following:

•A $40 million increase in Virginia FAC and West Virginia ENEC under-recoveries due to decreases in fuel revenues.

•A $39 million increase in West Virginia ENEC under-recoveries due to WVPSC orders for final recovery of West Virginia MRBC, Broadband and Vegetation Management under-recovery balances through ENEC rates.

•A $34 million decrease in Virginia FAC and West Virginia ENEC under-recoveries due to increased PJM revenues as a result of the performance of APCo’s generation during periods of high prices in July 2026.

•A $9 million increase in Virginia consumable expenses that were previously deferred prior to the Virginia SCC approving recovery of these costs through Virginia E-RAC rates starting in March 2026.

•A $4 million increase in Virginia renewable compliance expense.

•A $3 million increase in Virginia jurisdictional purchased power costs that are not recoverable through the Virginia FAC.

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

•An $8 million increase in employee-related costs.

•A $7 million increase in distribution expenses primarily due to vegetation management costs and storm restoration costs.

•A $6 million increase in transmission expenses primarily due to an increase in recoverable PJM 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.

•Depreciation and Amortization expenses increased $28 million primarily due to a July 2026 order approving a final true-up to recover past West Virginia MRBC costs.

•Interest Expense increased $21 million primarily due to higher long-term debt balances.

•Income Tax Expense decreased $25 million primarily due to the following:

•A $12 million decrease due to an increase in flow-through benefits.

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

•A $4 million decrease due to an increase in PTCs.

•Retail Revenues decreased $3 million primarily due to the following:

•A $114 million decrease in fuel revenues.

•A $21 million decrease in weather-normalized revenues primarily in the residential class.

•A $110 million increase in base rate and rider revenues.

•A $15 million increase in weather-related usage primarily due to an 18% increase in cooling degree days.

•Off-system Sales increased $9 million primarily due to margins in July 2026 attributable to increased PJM prices.

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

•A $37 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 $81 million primarily due to the following:

•A $152 million increase in Virginia FAC and West Virginia ENEC under-recoveries due to decreases in fuel revenues.

•A $39 million increase in West Virginia ENEC under-recoveries due to WVPSC orders for final recovery of West Virginia MRBC, Broadband and Vegetation Management under-recovery balances through ENEC rates.

•A $57 million decrease in Virginia FAC and West Virginia ENEC under-recoveries due to increased PJM revenues as a result of the performance of APCo’s generation during periods of high prices in July 2026.

•A $21 million increase in Virginia consumable expenses that were previously deferred prior to the Virginia SCC approving recovery of these costs through Virginia E-RAC rates starting March 2026.

•A $14 million increase in Virginia jurisdictional purchased power costs that are not recoverable through the Virginia FAC.

•A $14 million decrease in West Virginia ENEC under-recovery as a result of the June 2025 FERC NOLC order.

•A $12 million increase in Virginia renewable compliance expense.

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

•A $17 million increase in employee-related costs.

•A $15 million increase in steam generation expenses primarily due to increased plant maintenance.

•An $8 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 increased $26 million primarily due to the cumulative regulatory deferral true-up for the impact of CAMT expense incurred related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•Taxes Other Than Income Taxes increased $14 million primarily due to the following:

•A $7 million increase due to higher business and occupation taxes.

•A $5 million increase in property taxes.

•Interest Expense increased $38 million primarily due to higher long-term debt balances.

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

•A $25 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.

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

•A $7 million decrease due to a decrease in state taxes.

•A $6 million decrease due to an increase in amortization of Excess ADIT.

•A $5 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 $78 million primarily due to the following:

•A $69 million increase in weather-normalized revenues primarily in the commercial class.

•A $26 million increase in fuel revenues.

•A $24 million decrease in rider revenues.

•Other Revenues increased $5 million primarily due to an increase in River Transportation Division barging revenues.

•Purchased Electricity from AEP Affiliates expenses increased $21 million primarily due to an increase in purchased electricity from AEGCo.

•A $17 million increase in distribution expenses primarily due to an increase in storm restoration costs and vegetation management costs.

•A $12 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $10 million increase in steam generation expenses primarily due to the acquisition of generation facilities.

•A $10 million increase in employee-related costs.

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

•A $10 million increase due to a higher depreciable base.

•A $3 million increase due to the acquisition of generation facilities.

•A $5 million decrease due to Michigan PTC deferral activity.

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

•Income Tax Expense increased $17 million primarily due to a decrease in PTCs.

•Retail Revenues increased $327 million primarily due to the following:

•A $193 million increase in weather-normalized revenues primarily in the commercial class.

•A $91 million increase in fuel revenues.

•A $31 million increase in rider revenues.

•A $19 million increase due to a decrease in regulatory provisions for refund.

•An $8 million decrease in weather-related usage primarily due to a 5% decrease in cooling degree days and a 4% decrease in heating degree days.

•Off-system Sales increased $42 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 $12 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 $80 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 increased $14 million primarily due to an increase in purchased electricity from AEGCo.

•Other Operation and Maintenance expenses increased $110 million primarily due to the following:

•A $38 million increase in transmission expenses primarily due to a $29 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.

•A $24 million increase in distribution expenses primarily due to an increase in storm restoration costs and vegetation management costs.

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

•A $14 million increase in employee-related costs.

•Depreciation and Amortization expenses increased $25 million primarily due to the following:

•A $21 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 the Indiana tax rider.

•A $6 million increase due to acquisitions of generation facilities.

•An $11 million decrease due to Michigan PTC deferral activity.

•Other Income increased $9 million primarily due to an increase in AFUDC driven by a higher AFUDC equity base and increased equity return rates.

•Interest Expense increased $26 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $76 million primarily due to the following:

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

•A $22 million increase due to an increase in pretax book income.

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

ASSETS

(dollars in millions)

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

•Retail Revenues increased $172 million primarily due to the following:

•A $114 million increase in rider revenues.

•A $40 million increasedue to higher prices for purchased power to serve SSO customers.

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

•A $5 million increase in weather-related usage due to an 8% increase in cooling degree days.

•Off-system Sales decreased$32 million primarilydue to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•Transmission Revenues increased $6 million primarily due to continued transmission investment.

•Other Revenues decreased $8 million primarily due to lower third-party Legacy Generation Resource Rider revenues as a result of approved legislation in Ohio in May 2025, which ended the retail recovery of OVEC purchased power costs.

•Purchased Electricity for Resale expenses decreased $14 million primarily due to the following:

•A $34 million decrease in OVEC purchased power costs due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•An $8 million decrease as a result of legislation approved in Ohio in 2025 related to the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and OVEC-related revenues from PJM.

•A $2 million decrease in recoverable alternative energy rider expenses.

•A $36 million increase in recoverable auction purchases to serve SSO customers.

•Purchased Electricity from AEP Affiliates increased $8 million primarily due to an increase in recoverable purchases to serve SSO customers.

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

•An $86 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $14 million increase in distribution expenses primarily related to recoverable storm restoration costs and recoverable vegetation management expenses.

•A $7 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•Depreciation and Amortization increased $12 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $8 million primarily due to higher property taxes.

•Income Tax Expense decreased $5 million primarily due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 base rate case.

•Retail Revenues increased $314 million primarily due to the following:

•A $198 million increase in rider revenues.

•A $99 million increase due to higher prices for purchased power to serve SSO customers.

•A $20 million increase in weather-normalized revenues primarily in the residential and commercial classes.

•A $14 million decrease in weather-related usage driven by a 4% decrease in heating degree days.

•Off-system Sales decreased $14 million primarily due to the following:

•A $32 million decrease due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•An $18 million increase due to increased sales of OVEC purchased power in the first half of 2026 driven by higher market prices and volumes.

•Transmission Revenues increased $26 million primarily due to continued transmission investment.

•Other Revenues decreased $14 million primarily due to the following:

•A $24 million decrease in third-party Legacy Generation Resource Rider revenues as a result of approved legislation in Ohio in May 2025, which ended the retail recovery of OVEC purchased power costs.

•A $4 million increase in affiliated rent revenue.

•A $3 million increase primarily due to customer-sited projects.

•Purchased Electricity for Resale expenses decreased $27 million primarily due to the following:

•A $57 million decrease in OVEC purchased power costs due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•A $52 million decrease as a result of legislation approved in Ohio in 2025 related to the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and OVEC-related revenues from PJM.

•An $86 million increase in recoverable auction purchases to serve SSO customers.

•Purchased Electricity from AEP Affiliates expenses increased $13 million primarily due to an increase in recoverable purchases to serve SSO customers.

•Other Operation and Maintenance expenses increased $215 million primarily due to the following:

•A $151 million increase in transmission expenses primarily due to a $134 million increase in recoverable PJM transmission expenses and a $12 million increase in recoverable transmission storm restoration costs and vegetation management expenses.

•A $28 million increase in distribution expenses primarily related to recoverable vegetation management expenses and recoverable storm restoration costs.

•A $22 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•Depreciation and Amortization expenses increased $25 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $33 million primarily due to the following:

•A $25 million increase due to higher property taxes.

•An $8 million increase in state excise taxes due to increased billed KWhs.

•Income Tax Expense decreased $18 million primarily due to the following:

•A $30 million decrease due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 base rate case.

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

ASSETS

(dollars in millions)

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

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

•Retail Revenues increased $173 million primarily due to the following:

•A $148 million increase in rider revenues, inclusive of $75 million of 2026 interim rate rider revenue.

•A $56 million increase in weather-related usage primarily due to a 41% increase in cooling degree days.

•A $6 million increase in weather-normalized revenues primarily in the industrial class, partially offset by a decrease in the residential class.

•A $36 million decrease in fuel revenue primarily due to lower authorized fuel rates.

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

•Other Revenues decreased $6 million primarily due to lower associated business development revenues and lower gains on the sale of environmental credits.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $64 million primarily due to a $37 million decrease related to the impact on deferred fuel costs from decreased fuel revenues and a $25 million decrease in recoverable PTCs.

•Depreciation and Amortization expenses increased $69 million primarily due to a higher depreciable base.

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

•Income Tax Benefit decreased $53 million primarily due to the following:

•A $33 million decrease due to an increase in pretax book income.

•A $17 million decrease due to a decrease in PTCs.

•Retail Revenues increased $276 million primarily due to the following:

•A $274 million increase in rider revenues, inclusive of $75 million of 2026 interim rate rider revenue.

•A $62 million increase in weather-related usage primarily due to a 39% increase in cooling degree days.

•A $48 million decrease in fuel revenue primarily due to lower authorized fuel rates.

•An $11 million decrease in weather-normalized revenues primarily in the residential class, partially offset by an increase in industrial class.

•Other Revenues decreased $8 million primarily due to lower associated business development revenues and lower gains on the sale of environmental credits.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $21 million primarily dueto a $47 million decrease related to the impact on deferred fuel costs from decreased fuel and other revenues, partially offset by a $28 million increase in recoverable PTCs.

•Other Operation and Maintenance expenses increased $67 million primarily due to the following:

•A $30 million increase in generation expenses primarily due to acquisitions of generation facilities.

•A $13 million increase in employee-related costs.

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

•A $7 million increase intransmission expenses primarily due to:

•A $33 million increase in SPP expenses.

•A $19 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $12 million decrease due to the refund of SPP upgrade costs.

•Depreciation and Amortization expenses increased $80 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $10 million primarily due to property taxes on acquired generation facilities.

•Interest Expense increased $35 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $13 million primarilydue to the following:

•A $20 million decrease due to an increase 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.

•A $21 million increase due to an increase in PTCs.

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 $63 million primarily due to the following:

•A $31 million increase due to the Arkansas base rate case.

•A $29 million increase in rider revenues primarily in the Louisiana jurisdiction.

•A $20 million increase in weather-related usage primarily due to a 15% increase in cooling degree days.

•An $18 million decrease due to a credit to certain existing wholesale generation customers.

•A $7 million decrease in weather-normalized revenues across all classes.

•Transmission Revenues decreased $16 million primarily due to a $12 million repayment of SPP upgrade credits, offset by an equal amount of incremental SPP upgrade costs in Other Operation and Maintenance expenses.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $13 million primarily due toincreased gas generation and higher coal prices.

•Interest Expense increased $25 million primarily due to the following:

•A $19 million increase due to higher long-term debt balances.

•A $4 million increase attributable to the interest portion of credits owed to wholesale customers.

•Income Tax Benefit decreased $6 million primarily due to a decrease in PTCs.

•Retail Revenues increased $105 million primarily due to the following:

•An $82 million increase in rider revenues primarily in the Louisiana jurisdiction.

•A $64 million increase due to the Arkansas base rate case.

•A $39 million increase in weather-normalized revenues across all classes.

•A $53 million decrease in fuel revenue due to a $43 million refund of the Texas over-recovered fuel balance and a $10 million decrease primarily due to lower authorized rates in Arkansas and Louisiana.

•A $41 million decrease due to a credit to certain existing wholesale generation customers.

•Transmission Revenues decreased $6 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 $12 million decrease due to the repayment of SPP upgrade credits, offset by lower SPP upgrade costs in Other Operation and Maintenance expenses.

•A $34 million increase due to continued transmission investment.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $43 million primarily dueto the following:

•A $53 million decrease due to a decrease in the deferred fuel costs related to a $43 million Texas fuel refund and a $10 million decrease primarily due to lower authorized rates in Arkansas and Louisiana.

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

•A $14 million increase in recoverable PTCs.

•An $11 million increase in non-recoverable fuel costs primarily in Louisiana.

•A $28 million increase in generation expenses primarily due to a $16 million increase related to the acquisition of the Wagon Wheel Wind Facility.

•A $17 million increase in distribution expenses primarily due to overhead line maintenance.

•A $9 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.

•A $4 million decrease in transmission expenses primarily due to:

•A $12 million decrease due to the refund of SPP upgrade costs.

•A $12 million decrease in vegetation management costs.

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

•A $32 million increase in SPP expenses.

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

•Depreciation and Amortization expenses increased $40 million primarily due to the following:

•A $44 million increase due to a higher depreciable base including the Wagon Wheel Wind Facility.

•A $5 million decrease primarily due to higher over-recovery of costs and allowable returns associated with generation rider recovery.

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

•Allowance for Equity Funds Used During Construction increased $9 million primarily due to a higher AFUDC base.

•Interest Expense increased $61 million primarily due to the following:

•A $46 million increase due to higher long-term debt balances.

•A $7 million increase related to the Texas tax normalization rider amortization.

•A $4 million increase attributable to the interest portion of credits owed to wholesale customers.

•Income Tax Benefit increased $23 million primarily due to the following:

•A $48 million increase due to an increase in PTCs.

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

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

•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 108.

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 nine months ended September 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:

Upon settlement of the ATM Forward maturing December 2026, the Company will issue three million shares of common stock. However, as the forward price was greater than the average market price of the common shares as of September 30, 2026, the shares were not included in the computation of diluted EPS because to do so would be antidilutive. There wereno antidilutive shares outstanding as of September 30, 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 September 30, 2026, SWEPCo’s share of the net investment in the Pirkey Plant was $167 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 September 2026, a unanimous stipulation and settlement agreement was filed with the PUCT. The agreement provides for partial recovery of the remaining net book value of the Pirkey Plant over 19 years with no return on the unamortized balance. Due to the settlement in principle reached in April, 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 September 30, 2026, the Texas jurisdictional share of the net book value of the Pirkey Plant was $47 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 Federal EPA has proposed to approve. 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 September 30, 2026, the unrecovered value of these assets was $152 million, inclusive of ARO costs, which PSO is currently collecting in rates.

SWEPCo

In November 2020, management announced that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation. In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively. In February 2026, the APSC issued an order approving the application for a CCN. 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. In September 2026, the PUCT issued an order approving the stipulation and settlement agreement with a modification establishing aseven-year validity period for the order. Additionally, in July 2026, SWEPCo and the LPSC staff filed a joint stipulation agreement and term sheet with the LPSC agreeing the application for a CCN should be approved. In October, the LPSC issued an order approving the joint stipulation agreement.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of September 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 included $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)In May 2026, APCo issued securitization bonds that included $141 million of Virginia storm operation and maintenance costs.

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

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