For a detailed discussion of AEP’s market risks, see “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of AEP's Annual Report on Form 10-K for the year ended December 31, 2025. During the six months ended June 30, 2026, there were no material changes to disclosures about market risk, inclusive of credit risk, value at risk associated with risk management contracts and interest rate risk. See Note 9 – Derivatives and Hedging and Note 10 – Fair Value Measurements for additional information related to risk management contracts. 37 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONDENSED CONSOLIDATED STATEMENTS OF INCOME For the Three and Six Months Ended June 30, 2026 and 2025 (in millions, except per-share and share amounts) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 REVENUES Vertically Integrated Utilities $ 3,050 $ 2,934 $ 6,415 $ 6,020 Transmission and Distribution Utilities 1,568 1,443 3,162 2,958 Generation & Marketing 693 552 1,624 1,282 Other Revenues 134 158 264 290 TOTAL REVENUES 5,445 5,087 11,465 10,550 EXPENSES Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 1,603 1,541 3,721 3,394 Other Operation 814 538 1,564 1,290 Maintenance 444 390 855 709 Asset Impairments and Other Related Charges — — 31 — Depreciation and Amortization 910 854 1,817 1,687 Taxes Other Than Income Taxes 427 365 870 787 TOTAL EXPENSES 4,198 3,688 8,858 7,867 OPERATING INCOME 1,247 1,399 2,607 2,683 Other Income (Expense): Other Income 14 15 20 23 Allowance for Equity Funds Used During Construction 75 57 145 114 Non-Service Cost Components of Net Periodic Benefit Cost 19 35 57 70 Interest Expense (585) (489) (1,137) (984) INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS 770 1,017 1,692 1,906 Income Tax Expense (Benefit) 52 (251) 96 (126) Equity Earnings of Unconsolidated Subsidiaries 29 21 54 59 NET INCOME 747 1,289 1,650 2,091 Net Income Attributable to Noncontrolling Interests 34 63 63 65 EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 713 $ 1,226 $ 1,587 $ 2,026 WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING 544,163,341 534,283,554 543,127,062 533,839,985 TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 1.31 $ 2.29 $ 2.92 $ 3.80 WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 550,628,111 536,425,635 548,846,865 535,547,029 TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 1.30 $ 2.29 $ 2.89 $ 3.78 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 38 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 Net Income $ 747 $ 1,289 $ 1,650 $ 2,091 OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES Cash Flow Hedges, Net of Tax of $6 and $(9) for the Three Months Ended June 30, 2026 and 2025, Respectively, and $2 and $(3) for the Six Months Ended June 30, 2026 and 2025, Respectively 22 (33) 7 (10) Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $1 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively 1 — 2 1 TOTAL OTHER COMPREHENSIVE INCOME (LOSS) 23 (33) 9 (9) TOTAL COMPREHENSIVE INCOME 770 1,256 1,659 2,082 Total Comprehensive Income Attributable To Noncontrolling Interests 34 63 63 65 TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 736 $ 1,193 $ 1,596 $ 2,017 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 39 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) AEP Common Shareholders Common Stock Accumulated Other Comprehensive Income (Loss) Shares Amount Paid-in Capital Retained Earnings Noncontrolling Interests Total TOTAL EQUITY – DECEMBER 31, 2024 534 $ 3,472 $ 9,606 $ 13,869 $ (3) $ 42 $ 26,986 Issuance of Common Stock 1 7 68 75 Common Stock Dividends (500) (a) (1) (501) Other Changes in Equity (22) (22) Net Income 800 2 802 Other Comprehensive Income 24 24 TOTAL EQUITY – MARCH 31, 2025 535 3,479 9,652 14,169 21 43 27,364 Issuance of Common Stock 1 4 53 57 Common Stock Dividends (499) (a) (1) (500) Other Changes in Equity 8 8 Midwest Transmission Holdings Noncontrolling Interest Transaction 1,791 992 2,783 Net Income 1,226 63 1,289 Other Comprehensive Loss (33) (33) TOTAL EQUITY – JUNE 30, 2025 536 $ 3,483 $ 11,504 $ 14,896 $ (12) $ 1,097 $ 30,968 TOTAL EQUITY – DECEMBER 31, 2025 542 $ 3,523 $ 12,138 $ 15,441 $ 36 $ 1,080 $ 32,218 Issuance of Common Stock 3 21 337 358 Capital Contributions from Noncontrolling Interest 96 96 Common Stock Dividends (520) (b) (520) Dividends Paid to Noncontrolling Interest (35) (35) Other Changes in Equity (28) (28) Net Income 874 29 903 Other Comprehensive Loss (14) (14) TOTAL EQUITY – MARCH 31, 2026 545 3,544 12,447 15,795 22 1,170 32,978 Issuance of Common Stock 1 2 45 47 Capital Contributions from Noncontrolling Interest 60 60 Common Stock Dividends (519) (b) (519) Dividends Paid to Noncontrolling Interest (54) (54) Other Changes in Equity 7 7 Net Income 713 34 747 Other Comprehensive Income 23 23 TOTAL EQUITY – JUNE 30, 2026 546 $ 3,546 $ 12,499 $ 15,989 $ 45 $ 1,210 $ 33,289 (a) Cash dividends declared per AEP common share were $0.93. (b) Cash dividends declared per AEP common share were $0.95. See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 40 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONDENSED CONSOLIDATED BALANCE SHEETS ASSETS June 30, 2026 and December 31, 2025 (in millions) (Unaudited) June 30, December 31, 2026 2025 CURRENT ASSETS Cash and Cash Equivalents $ 375 $ 197 Restricted Cash(June 30, 2026 and December 31, 2025 Amounts Include $72 and $71, Respectively, Related to Restoration Funding, Appalachian Consumer Rate Relief Funding, Appalachian Recovery Funding, Storm Recovery Funding and Cost Recovery Funding) 72 71 Other Temporary Investments(June 30, 2026 and December 31, 2025 Amounts Include $220 and $209, Respectively, Related to EIS) 228 220 Accounts Receivable: Customers 1,266 1,166 Accrued Unbilled Revenues 360 421 Pledged Accounts Receivable – AEP Credit 1,396 1,272 Miscellaneous 70 60 Allowance for Credit Losses (57) (52) Total Accounts Receivable 3,035 2,867 Fuel 606 576 Materials and Supplies 1,183 1,046 Risk Management Assets 533 352 Accrued Tax Benefits 278 85 Regulatory Asset for Under-Recovered Fuel Costs 525 426 Prepayments and Other Current Assets 299 212 TOTAL CURRENT ASSETS 7,134 6,052 PROPERTY, PLANT AND EQUIPMENT Electric: Generation 26,707 28,388 Transmission 43,764 42,557 Distribution 34,626 33,364 Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 9,406 8,635 Construction Work in Progress 9,696 7,635 Total Property, Plant and Equipment 124,199 120,579 Accumulated Depreciation and Amortization 27,526 28,205 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 96,673 92,374 OTHER NONCURRENT ASSETS Regulatory Assets 5,021 4,804 Securitized Assets 2,252 933 Spent Nuclear Fuel and Decommissioning Trusts 5,241 4,916 Goodwill 53 53 Long-term Risk Management Assets 235 265 Operating Lease Assets 642 661 Deferred Charges and Other Noncurrent Assets 4,319 4,402 TOTAL OTHER NONCURRENT ASSETS 17,763 16,034 TOTAL ASSETS $ 121,570 $ 114,460 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 41 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONDENSED CONSOLIDATED BALANCE SHEETS LIABILITIES AND EQUITY June 30, 2026 and December 31, 2025 (in millions, except per-share and share amounts) (Unaudited) June 30, December 31, 2026 2025 CURRENT LIABILITIES Accounts Payable $ 3,969 $ 3,429 Short-term Debt: Securitized Debt for Receivables – AEP Credit 900 900 Other Short-term Debt 1,128 608 Total Short-term Debt 2,028 1,508 Long-term Debt Due Within One Year (June 30, 2026 and December 31, 2025 Amounts Include $215 and $207, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Appalachian Recovery Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding) 2,821 3,194 Risk Management Liabilities 152 132 Customer Deposits 515 507 Accrued Taxes 1,799 2,002 Accrued Interest 590 544 Obligations Under Operating Leases 94 100 Other Current Liabilities 2,187 1,898 TOTAL CURRENT LIABILITIES 14,155 13,314 NONCURRENT LIABILITIES Long-term Debt(June 30, 2026 and December 31, 2025 Amounts Include $2,566 and $1,294, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Appalachian Recovery Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding) 47,987 44,128 Long-term Risk Management Liabilities 175 178 Deferred Income Taxes 11,485 10,951 Regulatory Liabilities and Deferred Investment Tax Credits 8,622 8,362 Asset Retirement Obligations 3,645 3,556 Employee Benefits and Pension Obligations 267 232 Obligations Under Operating Leases 568 578 Deferred Credits and Other Noncurrent Liabilities 1,313 905 TOTAL NONCURRENT LIABILITIES 74,062 68,890 TOTAL LIABILITIES 88,217 82,204 Rate Matters (Note 4) Commitments, Guarantees and Contingencies (Note 5) Contingently Redeemable Performance Share Awards 64 38 EQUITY Common Stock – Par Value – $6.50 Per Share: 2026 2025 Shares Authorized 900,000,000 600,000,000 Shares Issued 545,549,444 542,048,288 (1,186,815 Shares were Held in Treasury as of June 30, 2026 and December 31, 2025, Respectively) 3,546 3,523 Paid-in Capital 12,499 12,138 Retained Earnings 15,989 15,441 Accumulated Other Comprehensive Income (Loss) 45 36 TOTAL AEP COMMON SHAREHOLDERS’ EQUITY 32,079 31,138 Noncontrolling Interests 1,210 1,080 TOTAL EQUITY 33,289 32,218 TOTAL LIABILITIES AND EQUITY $ 121,570 $ 114,460 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 42 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Six Months Ended June 30, 2026 2025 OPERATING ACTIVITIES Net Income $ 1,650 $ 2,091 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 1,817 1,687 Deferred Income Taxes 332 (54) Asset Impairments and Other Related Charges 31 — Allowance for Equity Funds Used During Construction (145) (114) Mark-to-Market of Risk Management Contracts (123) (241) Pension Contributions to Qualified Plan Trust — (95) Property Taxes 238 241 Deferred Fuel Over/Under-Recovery, Net 31 (41) Change in Other Noncurrent Assets (628) (440) Change in Other Noncurrent Liabilities 581 41 Changes in Certain Components of Working Capital: Accounts Receivable, Net (62) (176) Fuel, Materials and Supplies (162) 114 Accounts Payable 408 287 Accrued Taxes, Net (397) (469) Other Current Assets (27) 11 Other Current Liabilities (123) (171) Net Cash Flows from Operating Activities 3,421 2,671 INVESTING ACTIVITIES Construction Expenditures (5,606) (4,020) Purchases of Investment Securities (1,264) (1,337) Sales of Investment Securities 1,216 1,311 Acquisitions of Generation Facilities (1,315) (1,359) Acquisitions of Nuclear Fuel (51) (45) Contribution in Aid of Construction Advances 425 106 Other Investing Activities (7) (3) Net Cash Flows Used for Investing Activities (6,602) (5,347) FINANCING ACTIVITIES Capital Contribution from Noncontrolling Interest 156 — Issuance of Common Stock 405 132 Issuance of Long-term Debt 5,045 3,163 Issuance of Short-term Debt with Original Maturities greater than 90 Days — 320 Change in Short-term Debt with Original Maturities less than 90 Days, Net 520 (764) Retirement of Long-term Debt (1,578) (1,324) Redemption of Short-term Debt with Original Maturities Greater than 90 Days — (578) Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs — 2,783 Dividends Paid on Common Stock (1,039) (999) Dividends Paid to Noncontrolling Interest (89) (2) Other Financing Activities (60) (22) Net Cash Flows from Financing Activities 3,360 2,709 Net Increase in Cash, Cash Equivalents and Restricted Cash 179 33 Cash, Cash Equivalents and Restricted Cash at Beginning of Period 268 246 Cash, Cash Equivalents and Restricted Cash at End of Period $ 447 $ 279 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 43 AEP TEXAS INC. AND SUBSIDIARIES MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS RESULTS OF OPERATIONS KWh Sales/Degree Days Summary of KWh Energy Sales Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in millions of KWhs) Retail: Residential 3,167 3,275 5,698 6,191 Commercial 4,710 4,719 9,768 8,818 Industrial 4,377 3,300 7,871 6,670 Miscellaneous 148 147 286 291 Total Retail 12,402 11,441 23,623 21,970 Summary of Heating and Cooling Degree Days Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in degree days) Actual – Heating 1 4 144 296 Normal – Heating 4 4 215 208 Actual – Cooling 900 992 1,124 1,153 Normal – Cooling 919 909 1,035 1,021 44 AEP Texas Inc. and Subsidiaries Reconciliation of 2025 to 2026 Net Income (in millions) Three Months Ended June 30, Six Months Ended June 30, 2025 Net Income $ 121 $ 223 Changes in Revenues: Retail Revenues 14 (7) Transmission Revenues 20 33 Other Revenues 6 15 Total Change in Revenues 40 41 Changes in Expenses and Other: Other Operation and Maintenance (26) (22) Depreciation and Amortization (13) (9) Taxes Other Than Income Taxes (2) — Allowance for Equity Funds Used During Construction 8 15 Non-Service Cost Components of Net Periodic Benefit Cost 1 1 Interest Expense (17) (10) Total Change in Expenses and Other (49) (25) Income Tax Expense 1 (6) 2026 Net Income $ 113 $ 233 Second Quarter of 2026 Compared to Second Quarter of 2025 The major components of the increase in Revenues were as follows: •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. These increases were partially offset by: •A $7 million decrease in weather-related usage primarily due to a 9% decrease in cooling degree days. •A $4 million regulatory refund provision established due to the probable, partial disallowance of UTM deferrals. •Transmission Revenues increased $20 million primarily due to the following: •A $21 million increase in transmission investments. This increase was partially offset by: •A $4 million regulatory refund provision established due to the probable, partial disallowance of UTM deferrals. •Other Revenues increased $6 million primarily due to the taxable portion of payments received from customers for large interconnection projects. Expenses and Other changed between years as follows: •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. 45 Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 The major components of the increase in Revenues were as follows: •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 $4 million regulatory refund provision established due to the probable, partial disallowance of UTM deferrals. These decreases were partially offset by: •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. This increase was partially offset by: •A $4 million regulatory refund provision established due to the probable, partial disallowance of UTM deferrals. •Other Revenues increased $15 million primarily due to the taxable portion of payments received from customers for large interconnection projects. Expenses and Other and 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. This increase was partially offset by: •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. This increase was partially offset by: •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. 46 AEP TEXAS INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF INCOME For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 REVENUES Electric Transmission and Distribution $ 560 $ 528 $ 1,073 $ 1,048 Sales to AEP Affiliates 1 2 3 3 Other Revenues 10 1 19 3 TOTAL REVENUES 571 531 1,095 1,054 EXPENSES Other Operation 194 164 356 330 Maintenance 27 31 51 55 Depreciation and Amortization 120 107 225 216 Taxes Other Than Income Taxes 40 38 85 85 TOTAL EXPENSES 381 340 717 686 OPERATING INCOME 190 191 378 368 Other Income (Expense): Interest Income 1 1 1 1 Allowance for Equity Funds Used During Construction 20 12 39 24 Non-Service Cost Components of Net Periodic Benefit Cost 6 5 12 11 Interest Expense (78) (61) (144) (134) INCOME BEFORE INCOME TAX EXPENSE 139 148 286 270 Income Tax Expense 26 27 53 47 NET INCOME $ 113 $ 121 $ 233 $ 223 The common stock of AEP Texas is wholly-owned by Parent. See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 47 AEP TEXAS INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Net Income $ 113 $ 121 $ 233 $ 223 OTHER COMPREHENSIVE LOSS, NET OF TAXES Cash Flow Hedges, Net of Tax of $0 and $0 for Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively — — — (1) TOTAL COMPREHENSIVE INCOME $ 113 $ 121 $ 233 $ 222 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 48 AEP TEXAS INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024 $ 2,093 $ 2,795 $ (3) $ 4,885 Net Income 102 102 Other Comprehensive Loss (1) (1) TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2025 2,093 2,897 (4) 4,986 Capital Contribution from Parent 250 250 Net Income 121 121 TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2025 $ 2,343 $ 3,018 $ (4) $ 5,357 TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025 $ 2,546 $ 3,283 $ (3) $ 5,826 Net Income 120 120 TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2026 2,546 3,403 (3) 5,946 Capital Contribution from Parent 1 1 Net Income 113 113 TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2026 $ 2,547 $ 3,516 $ (3) $ 6,060 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 49 AEP TEXAS INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS ASSETS June 30, 2026 and December 31, 2025 (in millions) (Unaudited) June 30, December 31, 2026 2025 CURRENT ASSETS Restricted Cash (June 30, 2026 and December 31, 2025 Amounts Include $13 and $14, Respectively, Related to Restoration Funding) $ 13 $ 14 Advances to Affiliates 7 7 Accounts Receivable: Customers 244 189 Affiliated Companies 11 15 Accrued Unbilled Revenues 118 101 Total Accounts Receivable 373 305 Materials and Supplies 225 168 Prepayments and Other Current Assets 31 15 TOTAL CURRENT ASSETS 649 509 PROPERTY, PLANT AND EQUIPMENT Electric: Transmission 8,458 8,229 Distribution 7,200 6,835 Other Property, Plant and Equipment 1,282 1,239 Construction Work in Progress 2,233 1,766 Total Property, Plant and Equipment 19,173 18,069 Accumulated Depreciation and Amortization 2,260 2,205 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 16,913 15,864 OTHER NONCURRENT ASSETS Regulatory Assets 444 402 Securitized Assets(June 30, 2026 and December 31, 2025 Amounts Include $82 and $94, Respectively, Related to Restoration Funding) 82 94 Operating Lease Assets 49 52 Deferred Charges and Other Noncurrent Assets 222 154 TOTAL OTHER NONCURRENT ASSETS 797 702 TOTAL ASSETS $ 18,359 $ 17,075 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 50 AEP TEXAS INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS LIABILITIES AND COMMON SHAREHOLDER’S EQUITY June 30, 2026 and December 31, 2025 (in millions) (Unaudited) June 30, December 31, 2026 2025 CURRENT LIABILITIES Advances from Affiliates $ 354 $ 188 Accounts Payable: General 595 652 Affiliated Companies 43 60 Long-term Debt Due Within One Year – Nonaffiliated(June 30, 2026 and December 31, 2025 Amounts Include $25 and $25, Respectively, Related to Restoration Funding) 25 75 Accrued Taxes 151 118 Accrued Interest 73 64 Security Deposits 79 87 Contribution in Aid of Construction Advances 223 67 Obligations Under Operating Leases 13 14 Other Current Liabilities 72 93 TOTAL CURRENT LIABILITIES 1,628 1,418 NONCURRENT LIABILITIES Long-term Debt – Nonaffiliated(June 30, 2026 and December 31, 2025 Amounts Include $65 and $78, Respectively, Related to Restoration Funding) 7,671 6,941 Deferred Income Taxes 1,522 1,430 Regulatory Liabilities and Deferred Investment Tax Credits 1,253 1,286 Obligations Under Operating Leases 38 40 Deferred Credits and Other Noncurrent Liabilities 187 134 TOTAL NONCURRENT LIABILITIES 10,671 9,831 TOTAL LIABILITIES 12,299 11,249 Rate Matters (Note 4) Commitments, Guarantees and Contingencies (Note 5) COMMON SHAREHOLDER’S EQUITY Paid-in Capital 2,547 2,546 Retained Earnings 3,516 3,283 Accumulated Other Comprehensive Income (Loss) (3) (3) TOTAL COMMON SHAREHOLDER’S EQUITY 6,060 5,826 TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 18,359 $ 17,075 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 51 AEP TEXAS INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Six Months Ended June 30, 2026 2025 OPERATING ACTIVITIES Net Income $ 233 $ 223 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 225 216 Deferred Income Taxes 75 36 Allowance for Equity Funds Used During Construction (39) (24) Pension Contributions to Qualified Plan Trust — (12) Property Taxes (61) (58) Change in Other Noncurrent Assets (93) (50) Change in Other Noncurrent Liabilities 70 35 Changes in Certain Components of Working Capital: Accounts Receivable, Net (45) (31) Materials and Supplies (57) 21 Accounts Payable 72 3 Accrued Taxes, Net 33 15 Other Current Assets (16) 8 Other Current Liabilities (37) (23) Net Cash Flows from Operating Activities 360 359 INVESTING ACTIVITIES Construction Expenditures (1,449) (863) Contribution in Aid of Construction Advances 247 35 Other Investing Activities (2) (3) Net Cash Flows Used for Investing Activities (1,204) (831) FINANCING ACTIVITIES Capital Contribution from Parent 1 250 Issuance of Long-term Debt – Nonaffiliated 741 400 Change in Advances from Affiliates, Net 166 (175) Retirement of Long-term Debt – Nonaffiliated (62) (12) Other Financing Activities (3) (1) Net Cash Flows from Financing Activities 843 462 Net Decrease in Cash, Cash Equivalents and Restricted Cash (1) (10) Cash, Cash Equivalents and Restricted Cash at Beginning of Period 14 24 Cash, Cash Equivalents and Restricted Cash at End of Period $ 13 $ 14 SUPPLEMENTARY INFORMATION Cash Paid for Interest, Net of Capitalized Amounts $ 149 $ 125 Construction Expenditures Included in Current Liabilities as of June 30, 357 207 Contributions in Aid of Construction Advances Included in Current Assets as of June 30, 23 — See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 52 AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS RESULTS OF OPERATIONS Summary of Investment in Transmission Assets for AEPTCo As of June 30, 2026 2025 (in millions) Plant In Service $ 17,671 $ 16,090 Construction Work in Progress 2,636 2,105 Accumulated Depreciation and Amortization 2,075 1,760 Total Transmission Property, Net $ 18,232 $ 16,435 AEP Transmission Company, LLC and Subsidiaries Reconciliation of 2025 to 2026 Earnings Attributable to AEP Member (in millions) Three Months Ended June 30, Six Months Ended June 30, 2025 Earnings Attributable to AEP Member $ 556 $ 767 Changes in Transmission Revenues: Transmission Revenues (154) (103) Total Change in Transmission Revenues (154) (103) Changes in Expenses and Other: Other Operation and Maintenance (11) (28) Depreciation and Amortization (9) (23) Taxes Other Than Income Taxes (10) (24) Interest Income — 2 Allowance for Equity Funds Used During Construction 5 5 Interest Expense (7) (17) Total Change in Expenses and Other (32) (85) Income Tax Expense (208) (207) Net Income Attributable to Noncontrolling Interest 30 3 2026 Earnings Attributable to AEP Member $ 192 $ 375 Second Quarter of 2026 Compared to Second Quarter of 2025 The major components of the decrease in Transmission Revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows: •Transmission Revenues decreased $154 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. This decrease was partially offset by: •A $60 million increase due to continued transmission investment. 53 Expenses and Other, Income Tax Expense and Net Income Attributable to Noncontrolling Interest changed between years as follows: •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 $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. This increase was partially offset by: •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 $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. This decrease was partially offset by: •A $24 million increase due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025. Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 The major components of the decrease in Transmission Revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows: •Transmission Revenues decreased $103 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. This decrease was partially offset by: •A $111 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 $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 $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. This increase was partially offset by: •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 $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. This decrease was partially offset by: •A $52 million increase due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025. 54 AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF INCOME For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 REVENUES Transmission Revenues $ 110 $ 111 $ 220 $ 217 Sales to AEP Affiliates 477 470 947 900 (Provision for)/Reversal of - Revenue Refund – Affiliated (3) 127 (5) 120 (Provision for)/Reversal of - Revenue Refund – Nonaffiliated (3) 34 (3) 32 Other Revenues 7 — 7 — TOTAL REVENUES 588 742 1,166 1,269 EXPENSES Other Operation 45 36 86 65 Maintenance 8 6 18 11 Depreciation and Amortization 128 119 256 233 Taxes Other Than Income Taxes 86 76 174 150 TOTAL EXPENSES 267 237 534 459 OPERATING INCOME 321 505 632 810 Other Income (Expense): Interest Income – Affiliated 2 2 4 2 Allowance for Equity Funds Used During Construction 26 21 48 43 Interest Expense (64) (57) (129) (112) INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 285 471 555 743 Income Tax Expense (Benefit) 62 (146) 122 (85) NET INCOME 223 617 433 828 Net Income Attributable to Noncontrolling Interest 31 61 58 61 EARNINGS ATTRIBUTABLE TO AEP MEMBER $ 192 $ 556 $ 375 $ 767 AEPTCo is wholly-owned by AEP Transmission Holdco. See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 55 AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Paid-in Capital Retained Earnings Noncontrolling Interest Total TOTAL MEMBER'S EQUITY – DECEMBER 31, 2024 $ 3,101 $ 3,850 $ — $ 6,951 Capital Contribution from AEP Member 32 32 Dividends Paid to AEP Member (42) (42) Net Income 211 211 TOTAL MEMBER'S EQUITY – MARCH 31, 2025 3,133 4,019 — 7,152 Capital Contribution from AEP Member 8 8 Dividends Paid to AEP Member (2,836) (2,836) Midwest Transmission Holdings Noncontrolling Interest Transaction 1,791 992 2,783 Net Income 556 61 617 TOTAL MEMBER'S EQUITY – JUNE 30, 2025 $ 4,932 $ 1,739 $ 1,053 $ 7,724 TOTAL MEMBER'S EQUITY – DECEMBER 31, 2025 $ 4,962 $ 1,651 $ 1,030 $ 7,643 Capital Contribution from AEP Member 233 233 Capital Contribution from Noncontrolling Interest 96 96 Dividends Paid to Noncontrolling Interest (33) (33) Net Income 183 27 210 TOTAL MEMBER'S EQUITY – MARCH 31, 2026 5,195 1,834 1,120 8,149 Capital Contribution from AEP Member 16 16 Capital Contribution from Noncontrolling Interest 31 31 Dividends Paid to AEP Member (141) (141) Dividends Paid to Noncontrolling Interest (54) (54) Net Income 192 31 223 TOTAL MEMBER'S EQUITY – JUNE 30, 2026 $ 5,211 $ 1,885 $ 1,128 $ 8,224 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 56 AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS ASSETS June 30, 2026 and December 31, 2025 (in millions) (Unaudited) June 30, December 31, 2026 2025 CURRENT ASSETS Advances to Affiliates $ 222 $ 71 Accounts Receivable: Customers 66 94 Affiliated Companies 177 153 Total Accounts Receivable 243 247 Prepayments and Other Current Assets 31 4 TOTAL CURRENT ASSETS 496 322 TRANSMISSION PROPERTY Transmission Property 17,085 16,542 Other Property, Plant and Equipment 586 571 Construction Work in Progress 2,636 2,005 Total Transmission Property 20,307 19,118 Accumulated Depreciation and Amortization 2,075 1,915 TOTAL TRANSMISSION PROPERTY – NET 18,232 17,203 OTHER NONCURRENT ASSETS Regulatory Assets 84 73 Deferred Property Taxes 187 326 Deferred Charges and Other Noncurrent Assets 77 75 TOTAL OTHER NONCURRENT ASSETS 348 474 TOTAL ASSETS $ 19,076 $ 17,999 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 57 AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS LIABILITIES AND MEMBER’S EQUITY June 30, 2026 and December 31, 2025 (in millions) (Unaudited) June 30, December 31, 2026 2025 CURRENT LIABILITIES Advances from Affiliates $ 58 $ 143 Accounts Payable: General 805 477 Affiliated Companies 113 164 Long-term Debt Due Within One Year – Nonaffiliated 425 425 Accrued Taxes 536 650 Accrued Interest 48 46 Contribution in Aid of Construction Advances 170 32 Obligations Under Operating Leases 1 1 Other Current Liabilities 15 9 TOTAL CURRENT LIABILITIES 2,171 1,947 NONCURRENT LIABILITIES Long-term Debt – Nonaffiliated 6,331 6,174 Deferred Income Taxes 1,542 1,481 Regulatory Liabilities 779 708 Obligations Under Operating Leases 1 2 Deferred Credits and Other Noncurrent Liabilities 28 44 TOTAL NONCURRENT LIABILITIES 8,681 8,409 TOTAL LIABILITIES 10,852 10,356 Rate Matters (Note 4) Commitments, Guarantees and Contingencies (Note 5) MEMBER’S EQUITY Paid-in Capital 5,211 4,962 Retained Earnings 1,885 1,651 TOTAL MEMBER’S EQUITY 7,096 6,613 Noncontrolling Interest 1,128 1,030 TOTAL EQUITY 8,224 7,643 TOTAL LIABILITIES AND EQUITY $ 19,076 $ 17,999 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 58 AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Six Months Ended June 30, 2026 2025 OPERATING ACTIVITIES Net Income $ 433 $ 828 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 256 233 Deferred Income Taxes 51 (137) Allowance for Equity Funds Used During Construction (48) (43) Property Taxes 139 131 Change in Other Noncurrent Assets (23) (46) Change in Other Noncurrent Liabilities (14) (152) Changes in Certain Components of Working Capital: Accounts Receivable, Net 53 (45) Accounts Payable (46) 5 Accrued Taxes, Net (132) (202) Other Current Assets (9) 8 Other Current Liabilities 7 (15) Net Cash Flows from Operating Activities 667 565 INVESTING ACTIVITIES Construction Expenditures (865) (787) Change in Advances to Affiliates, Net (151) (38) Contribution in Aid of Construction Advances 135 18 Other Investing Activities (4) 5 Net Cash Flows Used for Investing Activities (885) (802) FINANCING ACTIVITIES Capital Contribution from AEP Member 249 40 Capital Contribution from Noncontrolling Interest 127 — Issuance of Long-term Debt – Nonaffiliated 768 419 Retirement of Long-term Debt – Nonaffiliated (613) (90) Change in Advances from Affiliates, Net (85) (37) Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs — 2,783 Dividends Paid to AEP Member (141) (2,878) Dividends Paid to Noncontrolling Interest (87) — Net Cash Flows from Financing Activities 218 237 Net Change in Cash and Cash Equivalents — — Cash and Cash Equivalents at Beginning of Period — — Cash and Cash Equivalents at End of Period $ — $ — SUPPLEMENTARY INFORMATION Cash Paid for Interest, Net of Capitalized Amounts $ 124 $ 107 Construction Expenditures Included in Current Liabilities as of June 30, 667 219 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 59 APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS RESULTS OF OPERATIONS KWh Sales/Degree Days Summary of KWh Energy Sales Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in millions of KWhs) Retail: Residential 1,976 2,032 5,597 5,686 Commercial 1,443 1,465 2,941 2,965 Industrial 2,173 2,204 4,173 4,280 Miscellaneous 202 208 410 419 Total Retail 5,794 5,909 13,121 13,350 Wholesale (a) 534 576 985 1,303 Total KWhs 6,328 6,485 14,106 14,653 (a)Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers. Summary of Heating and Cooling Degree Days Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in degree days) Actual – Heating 48 69 1,382 1,433 Normal – Heating 79 80 1,360 1,359 Actual – Cooling 429 417 454 428 Normal – Cooling 394 387 400 393 60 Appalachian Power Company and Subsidiaries Reconciliation of 2025 to 2026 Net Income (in millions) Three Months Ended June 30, Six Months Ended June 30, 2025 Net Income $ 107 $ 272 Changes in Revenues: Retail Revenues (40) (56) Off-system Sales 2 2 Transmission Revenues 8 22 Other Revenues (1) (5) Total Change in Revenues (31) (37) Changes in Expenses and Other: Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 14 57 Other Operation and Maintenance (12) (28) Depreciation and Amortization 7 2 Taxes Other Than Income Taxes (7) (13) Interest Income (1) (1) Allowance for Equity Funds Used During Construction (2) (2) Non-Service Cost Components of Net Periodic Benefit Cost (2) (3) Interest Expense (9) (17) Total Change in Expenses and Other (12) (5) Income Tax Expense (14) 15 2026 Net Income $ 50 $ 245 Second Quarter of 2026 Compared to Second Quarter of 2025 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. These decreases were partially offset by: •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. This increase was partially offset by: •A $6 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates. Expenses and Other and Income Tax Expense changed between years as follows: •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. This decrease was partially offset by: •A $14 million prior year impact to the West Virginia ENEC as a result of the June 2025 FERC NOLC order. 61 •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. These increases were partially offset by: •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. This increase was partially offset by: •A $9 million decrease due to a decrease in pretax book income. Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 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. These decreases were partially offset by: •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. This increase was partially offset by: •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. Expenses and Other and Income Tax Expense changed between years as follows: •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. This decrease was partially offset by: •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. These increases were partially offset by: •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. This decrease was partially offset by: •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. 62 •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. These decreases were partially offset by: •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. 63 APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF INCOME For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 REVENUES Electric Generation, Transmission and Distribution $ 833 $ 876 $ 1,904 $ 1,974 Sales to AEP Affiliates 81 66 173 138 Other Revenues 2 5 6 8 TOTAL REVENUES 916 947 2,083 2,120 EXPENSES Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 277 291 641 698 Other Operation 203 211 420 433 Maintenance 104 84 203 162 Depreciation and Amortization 164 171 332 334 Taxes Other Than Income Taxes 45 38 92 79 TOTAL EXPENSES 793 795 1,688 1,706 OPERATING INCOME 123 152 395 414 Other Income (Expense): Interest Income 1 2 2 3 Allowance for Equity Funds Used During Construction 3 5 7 9 Non-Service Cost Components of Net Periodic Benefit Cost 4 6 8 11 Interest Expense (80) (71) (155) (138) INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 51 94 257 299 Income Tax Expense (Benefit) 1 (13) 12 27 NET INCOME $ 50 $ 107 $ 245 $ 272 The common stock of APCo is wholly-owned by Parent. See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 64 APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 Net Income $ 50 $ 107 $ 245 $ 272 OTHER COMPREHENSIVE LOSS, NET OF TAXES Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively (1) (1) (1) (1) Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively — — — — TOTAL OTHER COMPREHENSIVE LOSS (1) (1) (1) (1) TOTAL COMPREHENSIVE INCOME $ 49 $ 106 $ 244 $ 271 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 65 APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Common Stock Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2024 $ 260 $ 1,945 $ 3,532 $ 11 $ 5,748 Common Stock Dividends (50) (50) Net Income 165 165 TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2025 260 1,945 3,647 11 5,863 Capital Contribution from Parent 7 7 Net Income 107 107 Other Comprehensive Loss (1) (1) TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2025 $ 260 $ 1,952 $ 3,754 $ 10 $ 5,976 TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2025 $ 260 $ 1,957 $ 3,939 $ 24 $ 6,180 Capital Contribution from Parent 81 81 Net Income 195 195 TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2026 260 2,038 4,134 24 6,456 Common Stock Dividends (700) (700) Net Income 50 50 Other Comprehensive Loss (1) (1) TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2026 $ 260 $ 2,038 $ 3,484 $ 23 $ 5,805 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 66 APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS ASSETS June 30, 2026 and December 31, 2025 (in millions) (Unaudited) June 30, December 31, 2026 2025 CURRENT ASSETS Cash and Cash Equivalents $ 4 $ 5 Restricted Cash for Securitized Funding(June 30, 2026 and December 31, 2025 Amounts Include $25 and $18, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding) 25 18 Advances to Affiliates 17 17 Accounts Receivable: Customers 223 171 Affiliated Companies 165 142 Accrued Unbilled Revenues 61 112 Allowance for Credit Losses (2) (2) Total Accounts Receivable 447 423 Fuel 245 229 Materials and Supplies 157 139 Risk Management Assets 171 81 Regulatory Asset for Under-Recovered Fuel Costs 163 83 Prepayments and Other Current Assets 58 38 TOTAL CURRENT ASSETS 1,287 1,033 PROPERTY, PLANT AND EQUIPMENT Electric: Generation 5,688 7,886 Transmission 5,339 5,277 Distribution 6,074 5,938 Other Property, Plant and Equipment 1,218 1,175 Construction Work in Progress 878 802 Total Property, Plant and Equipment 19,197 21,078 Accumulated Depreciation and Amortization 5,135 6,365 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 14,062 14,713 OTHER NONCURRENT ASSETS Regulatory Assets 1,407 1,439 Securitized Assets(June 30, 2026 and December 31, 2025 Amounts Include $1,424 and $78, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding) 1,424 78 Employee Benefits and Pension Assets 257 251 Operating Lease Assets 97 95 Deferred Charges and Other Noncurrent Assets 175 183 TOTAL OTHER NONCURRENT ASSETS 3,360 2,046 TOTAL ASSETS $ 18,709 $ 17,792 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 67 APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS LIABILITIES AND COMMON SHAREHOLDER’S EQUITY June 30, 2026 and December 31, 2025 (Unaudited) June 30, December 31, 2026 2025 (in millions) CURRENT LIABILITIES Advances from Affiliates $ 126 $ 209 Accounts Payable: General 492 375 Affiliated Companies 122 173 Long-term Debt Due Within One Year – Nonaffiliated(June 30, 2026 and December 31, 2025 Amounts Include $65 and $30, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding) 1,315 1,131 Customer Deposits 99 94 Accrued Taxes 121 116 Obligations Under Operating Leases 14 15 Other Current Liabilities 297 271 TOTAL CURRENT LIABILITIES 2,586 2,384 NONCURRENT LIABILITIES Long-term Debt – Nonaffiliated(June 30, 2026 and December 31, 2025 Amounts Include $1,376 and $62, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding) 6,120 5,128 Deferred Income Taxes 2,236 2,130 Regulatory Liabilities and Deferred Investment Tax Credits 1,064 1,111 Asset Retirement Obligations 741 707 Employee Benefits and Pension Obligations 26 26 Obligations Under Operating Leases 84 81 Deferred Credits and Other Noncurrent Liabilities 47 45 TOTAL NONCURRENT LIABILITIES 10,318 9,228 TOTAL LIABILITIES 12,904 11,612 Rate Matters (Note 4) Commitments, Guarantees and Contingencies (Note 5) COMMON SHAREHOLDER’S EQUITY Common Stock – No Par Value: Authorized – 30,000,000 Shares Outstanding – 13,499,500 Shares 260 260 Paid-in Capital 2,038 1,957 Retained Earnings 3,484 3,939 Accumulated Other Comprehensive Income (Loss) 23 24 TOTAL COMMON SHAREHOLDER’S EQUITY 5,805 6,180 TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 18,709 $ 17,792 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 68 APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Six Months Ended June 30, 2026 2025 OPERATING ACTIVITIES Net Income $ 245 $ 272 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 332 334 Deferred Income Taxes 60 (5) Allowance for Equity Funds Used During Construction (7) (9) Mark-to-Market of Risk Management Contracts (80) (73) Deferred Fuel Over/Under-Recovery, Net (72) 6 Change in Regulatory Assets (96) (117) Change in Other Noncurrent Assets (40) 29 Change in Other Noncurrent Liabilities (19) 6 Changes in Certain Components of Working Capital: Accounts Receivable, Net (20) 6 Fuel, Materials and Supplies (34) 38 Accounts Payable 73 (61) Accrued Taxes, Net 1 (39) Other Current Assets (11) 18 Other Current Liabilities 17 (19) Net Cash Flows from Operating Activities 349 386 INVESTING ACTIVITIES Construction Expenditures (497) (528) Acquisitions of Assets (352) — Other Investing Activities 36 4 Net Cash Flows Used for Investing Activities (813) (524) FINANCING ACTIVITIES Capital Contribution from Parent 81 7 Issuance of Long-term Debt – Nonaffiliated 1,364 528 Change in Advances from Affiliates, Net (83) 78 Retirement of Long-term Debt – Nonaffiliated (191) (418) Principal Payments for Finance Lease Obligations (2) (4) Dividends Paid on Common Stock (700) (50) Other Financing Activities 1 1 Net Cash Flows from Financing Activities 470 142 Net Increase in Cash, Cash Equivalents and Restricted Cash for Securitized Funding 6 4 Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 23 20 Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $ 29 $ 24 SUPPLEMENTARY INFORMATION Cash Paid for Interest, Net of Capitalized Amounts $ 150 $ 134 Noncash Acquisitions Under Finance Leases 3 2 Construction Expenditures Included in Current Liabilities as of June 30, 126 115 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 69 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS RESULTS OF OPERATIONS KWh Sales/Degree Days Summary of KWh Energy Sales Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in millions of KWhs) Retail: Residential 1,102 1,097 2,610 2,650 Commercial 2,341 1,414 4,522 2,686 Industrial 1,812 1,856 3,539 3,604 Miscellaneous 10 9 22 22 Total Retail 5,265 4,376 10,693 8,962 Wholesale (a) 1,884 1,507 3,551 3,943 Total KWhs 7,149 5,883 14,244 12,905 (a)Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers. Summary of Heating and Cooling Degree Days Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in degree days) Actual – Heating 174 217 2,233 2,335 Normal – Heating 236 237 2,357 2,365 Actual – Cooling 222 280 223 280 Normal – Cooling 284 284 285 285 70 Indiana Michigan Power Company and Subsidiaries Reconciliation of 2025 to 2026 Net Income (in millions) Three Months Ended June 30, Six Months Ended June 30, 2025 Net Income $ 124 $ 182 Changes in Revenues: Retail Revenues 121 249 Off-system Sales (38) 44 Transmission Revenues (16) (13) Other Revenues (4) (7) Total Change in Revenues 63 273 Changes in Expenses and Other: Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (20) (76) Purchased Electricity from AEP Affiliates 8 7 Other Operation and Maintenance (17) (50) Depreciation and Amortization (9) (16) Taxes Other Than Income Taxes (4) (2) Other Income 4 7 Non-Service Cost Components of Net Periodic Benefit Cost (2) (3) Interest Expense (10) (18) Total Change in Expenses and Other (50) (151) Income Tax Expense (40) (59) 2026 Net Income $ 97 $ 245 Second Quarter of 2026 Compared to Second Quarter of 2025 The major components of the increase in Revenues were as follows: •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. These increases were partially offset by: •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. Expenses and Other and Income Tax Expense changed between years as follows: •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. 71 •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. Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 The major components of the increase in Revenues were as follows: •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. These increases were partially offset by: •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. Expenses and Other and Income Tax Expense changed between years as follows: •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. These increases were partially offset by: •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. These increases were partially offset by: •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. 72 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF INCOME For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 REVENUES Electric Generation, Transmission and Distribution $ 811 $ 736 $ 1,772 $ 1,495 Sales to AEP Affiliates 2 2 7 6 (Provision for)/Reversal of - Revenue Refund – Affiliated (4) 9 (4) 8 Provision for Refund – Nonaffiliated (23) (26) (71) (84) Other Revenues – Affiliated 13 14 27 30 Other Revenues – Nonaffiliated 1 2 2 5 TOTAL REVENUES 800 737 1,733 1,460 EXPENSES Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 152 132 384 308 Purchased Electricity from AEP Affiliates 58 66 135 142 Other Operation 202 177 390 348 Maintenance 80 88 156 148 Depreciation and Amortization 138 129 269 253 Taxes Other Than Income Taxes 26 22 50 48 TOTAL EXPENSES 656 614 1,384 1,247 OPERATING INCOME 144 123 349 213 Other Income (Expense): Other Income 8 4 16 9 Non-Service Cost Components of Net Periodic Benefit Cost 3 5 7 10 Interest Expense (49) (39) (92) (74) INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 106 93 280 158 Income Tax Expense (Benefit) 9 (31) 35 (24) NET INCOME $ 97 $ 124 $ 245 $ 182 The common stock of I&M is wholly-owned by Parent. See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 73 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 Net Income $ 97 $ 124 $ 245 $ 182 OTHER COMPREHENSIVE INCOME, NET OF TAXES Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively — — — — Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively — — — — TOTAL OTHER COMPREHENSIVE INCOME — — — — TOTAL COMPREHENSIVE INCOME $ 97 $ 124 $ 245 $ 182 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 74 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Common Stock Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2024 $ 57 $ 1,012 $ 2,328 $ — $ 3,397 Common Stock Dividends (50) (50) Net Income 58 58 TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2025 57 1,012 2,336 — 3,405 Capital Contribution from Parent 7 7 Net Income 124 124 TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2025 $ 57 $ 1,019 $ 2,460 $ — $ 3,536 TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2025 $ 57 $ 1,033 $ 2,692 $ 2 $ 3,784 Net Income 148 148 TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2026 57 1,033 2,840 2 3,932 Capital Contribution from Parent 25 25 Common Stock Dividends (50) (50) Net Income 97 97 TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2026 $ 57 $ 1,058 $ 2,887 $ 2 $ 4,004 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 75 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS ASSETS June 30, 2026 and December 31, 2025 (in millions) (Unaudited) June 30, December 31, 2026 2025 CURRENT ASSETS Cash and Cash Equivalents $ 2 $ 2 Advances to Affiliates 63 192 Accounts Receivable: Customers 110 103 Affiliated Companies 87 90 Accrued Unbilled Revenues — 17 Miscellaneous 14 2 Total Accounts Receivable 211 212 Fuel 65 61 Materials and Supplies 241 222 Risk Management Assets 22 10 Accrued Tax Benefits 31 32 Prepayments and Other Current Assets 82 53 TOTAL CURRENT ASSETS 717 784 PROPERTY, PLANT AND EQUIPMENT Electric: Generation 6,212 5,483 Transmission 2,155 2,055 Distribution 3,950 3,823 Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 1,389 1,058 Construction Work in Progress 541 403 Total Property, Plant and Equipment 14,247 12,822 Accumulated Depreciation, Depletion and Amortization 5,207 4,878 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 9,040 7,944 OTHER NONCURRENT ASSETS Regulatory Assets 553 585 Spent Nuclear Fuel and Decommissioning Trusts 5,241 4,916 Operating Lease Assets 46 52 Deferred Charges and Other Noncurrent Assets 344 344 TOTAL OTHER NONCURRENT ASSETS 6,184 5,897 TOTAL ASSETS $ 15,941 $ 14,625 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 76 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS LIABILITIES AND COMMON SHAREHOLDER’S EQUITY June 30, 2026 and December 31, 2025 (dollars in millions) (Unaudited) June 30, December 31, 2026 2025 CURRENT LIABILITIES Accounts Payable: General $ 304 $ 232 Affiliated Companies 110 125 Long-term Debt Due Within One Year – Nonaffiliated (June 30, 2026 and December 31, 2025 Amounts Include $91 and $117, Respectively, Related to DCC Fuel) 91 117 Customer Deposits 56 55 Accrued Taxes 98 112 Accrued Interest 55 42 Obligations Under Operating Leases 15 17 Regulatory Liability for Over-Recovered Fuel Costs 97 19 Other Current Liabilities 217 230 TOTAL CURRENT LIABILITIES 1,043 949 NONCURRENT LIABILITIES Long-term Debt – Nonaffiliated 4,055 3,444 Deferred Income Taxes 1,216 1,219 Regulatory Liabilities and Deferred Investment Tax Credits 3,317 2,938 Asset Retirement Obligations 2,208 2,165 Obligations Under Operating Leases 32 37 Deferred Credits and Other Noncurrent Liabilities 66 89 TOTAL NONCURRENT LIABILITIES 10,894 9,892 TOTAL LIABILITIES 11,937 10,841 Rate Matters (Note 4) Commitments, Guarantees and Contingencies (Note 5) COMMON SHAREHOLDER’S EQUITY Common Stock – No Par Value: Authorized – 2,500,000 Shares Outstanding – 1,400,000 Shares 57 57 Paid-in Capital 1,058 1,033 Retained Earnings 2,887 2,692 Accumulated Other Comprehensive Income (Loss) 2 2 TOTAL COMMON SHAREHOLDER’S EQUITY 4,004 3,784 TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 15,941 $ 14,625 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 77 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Six Months Ended June 30, 2026 2025 OPERATING ACTIVITIES Net Income $ 245 $ 182 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 269 253 Deferred Income Taxes (10) (46) Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net 37 (23) Allowance for Equity Funds Used During Construction (12) (8) Mark-to-Market of Risk Management Contracts (12) 7 Amortization of Nuclear Fuel 64 52 Deferred Fuel Over/Under-Recovery, Net 78 9 Change in Other Noncurrent Assets (26) (14) Change in Other Noncurrent Liabilities 94 55 Changes in Certain Components of Working Capital: Accounts Receivable, Net 10 (10) Fuel, Materials and Supplies (18) 26 Accounts Payable 22 28 Accrued Taxes, Net (13) (1) Other Current Assets 11 3 Other Current Liabilities (5) (14) Net Cash Flows from Operating Activities 734 499 INVESTING ACTIVITIES Construction Expenditures (367) (306) Change in Advances to Affiliates, Net 129 — Purchases of Investment Securities (1,249) (1,330) Sales of Investment Securities 1,209 1,294 Acquisitions of Generation Facilities (965) — Acquisitions of Nuclear Fuel (51) (45) Other Investing Activities 9 27 Net Cash Flows Used for Investing Activities (1,285) (360) FINANCING ACTIVITIES Capital Contribution from Parent 25 7 Issuance of Long-term Debt – Nonaffiliated 640 249 Change in Advances from Affiliates, Net — (101) Retirement of Long-term Debt – Nonaffiliated (63) (240) Principal Payments for Finance Lease Obligations (2) (3) Dividends Paid on Common Stock (50) (50) Other Financing Activities 1 1 Net Cash Flows from (Used for) Financing Activities 551 (137) Net Increase in Cash and Cash Equivalents — 2 Cash and Cash Equivalents at Beginning of Period 2 2 Cash and Cash Equivalents at End of Period $ 2 $ 4 SUPPLEMENTARY INFORMATION Cash Paid for Interest, Net of Capitalized Amounts $ 70 $ 72 Noncash Acquisitions Under Finance Leases 1 1 Construction Expenditures Included in Current Liabilities as of June 30, 99 82 Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 33 33 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 78 OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS RESULTS OF OPERATIONS KWh Sales/Degree Days Summary of KWh Energy Sales Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in millions of KWhs) Retail: Residential 2,952 3,024 6,953 7,119 Commercial 8,251 6,323 15,970 11,812 Industrial 3,727 3,748 7,105 7,134 Miscellaneous 23 25 51 53 Total Retail (a) 14,953 13,120 30,079 26,118 Wholesale (b) 256 464 899 1,131 Total KWhs 15,209 13,584 30,978 27,249 (a)Represents energy delivered to distribution customers. (b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM. Summary of Heating and Cooling Degree Days Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in degree days) Actual – Heating 132 170 1,996 2,077 Normal – Heating 172 173 1,991 1,993 Actual – Cooling 309 336 321 342 Normal – Cooling 325 323 328 325 79 Ohio Power Company and Subsidiaries Reconciliation of 2025 to 2026 Net Income (in millions) Three Months Ended June 30, Six Months Ended June 30, 2025 Net Income $ 103 $ 166 Changes in Revenues: Retail Revenues 90 142 Off-system Sales (7) 18 Transmission Revenues 13 20 Other Revenues (3) (6) Total Change in Revenues 93 174 Changes in Expenses and Other: Purchased Electricity for Resale 17 13 Purchased Electricity from AEP Affiliates (1) (5) Other Operation and Maintenance (90) (98) Depreciation and Amortization 4 (13) Taxes Other Than Income Taxes (28) (25) Other Income — (1) Allowance for Equity Funds Used During Construction (1) (1) Non-Service Cost Components of Net Periodic Benefit Cost (2) 3 Interest Expense 3 1 Total Change in Expenses and Other (98) (126) Income Tax Expense 11 13 Equity Earnings of Unconsolidated Subsidiaries — (1) 2026 Net Income $ 109 $ 226 Second Quarter of 2026 Compared to Second Quarter of 2025 The major components of the increase in Revenues were as follows: •Retail Revenues increased $90 million primarily due to the following: •A $79 million increase in rider revenues. •A $9 million increase due 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 by lower market prices. •Transmission Revenues increased $13 million primarily due to continued transmission investment. Expenses and Other and Income Tax Expense changed between years as follows: •Purchased Electricity for Resale expenses decreased $17 million primarily due to the following: •A $23 million decrease in OVEC purchased power costs. This decrease was partially offset by: •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. 80 •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. Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 The major components of the increase in Revenues were as follows: •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. These increases were partially offset by: •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. Expenses and Other and Income Tax Expense changed between years as follows: •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. These decreases were partially offset by: •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. This decrease was partially offset by: •A $10 million increase due to an increase in pretax book income. 81 OHIO POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF INCOME For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 REVENUES Electricity, Transmission and Distribution $ 994 $ 910 $ 2,063 $ 1,900 Sales to AEP Affiliates 14 6 27 16 Other Revenues 4 3 7 7 TOTAL REVENUES 1,012 919 2,097 1,923 EXPENSES Purchased Electricity for Resale 172 189 423 436 Purchased Electricity from AEP Affiliates 16 15 36 31 Other Operation 360 283 683 617 Maintenance 76 63 147 115 Depreciation and Amortization 91 95 202 189 Taxes Other Than Income Taxes 148 120 304 279 TOTAL EXPENSES 863 765 1,795 1,667 OPERATING INCOME 149 154 302 256 Other Income (Expense): Other Income — — — 1 Allowance for Equity Funds Used During Construction 6 7 13 14 Non-Service Cost Components of Net Periodic Benefit Cost 3 5 12 9 Interest Expense (37) (40) (77) (78) INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 121 126 250 202 Income Tax Expense 12 23 24 37 Equity Earnings of Unconsolidated Subsidiaries — — — 1 NET INCOME $ 109 $ 103 $ 226 $ 166 The common stock of OPCo is wholly-owned by Parent. See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 82 OHIO POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Common Stock Paid-in Capital Retained Earnings Total TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024 $ 321 $ 1,020 $ 2,543 $ 3,884 Common Stock Dividends (46) (46) Net Income 63 63 TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2025 321 1,020 2,560 3,901 Capital Contribution from Parent 2 2 Common Stock Dividends (25) (25) Net Income 103 103 TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2025 $ 321 $ 1,022 $ 2,638 $ 3,981 TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025 $ 321 $ 1,030 $ 2,800 $ 4,151 Capital Contribution from Parent 39 39 Net Income 117 117 TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2026 321 1,069 2,917 4,307 Capital Contribution from Parent 65 65 Net Income 109 109 Noncash Distribution to Parent (2) (2) TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2026 $ 321 $ 1,134 $ 3,024 $ 4,479 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 83 OHIO POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS ASSETS June 30, 2026 and December 31, 2025 (in millions) (Unaudited) June 30, December 31, 2026 2025 CURRENT ASSETS Cash and Cash Equivalents $ 5 $ 5 Accounts Receivable: Customers 153 109 Affiliated Companies 134 132 Accrued Unbilled Revenues 7 29 Total Accounts Receivable 294 270 Materials and Supplies 203 191 Prepayments and Other Current Assets 15 25 TOTAL CURRENT ASSETS 517 491 PROPERTY, PLANT AND EQUIPMENT Electric: Transmission 4,009 3,916 Distribution 8,057 7,661 Other Property, Plant and Equipment 1,307 1,289 Construction Work in Progress 808 811 Total Property, Plant and Equipment 14,181 13,677 Accumulated Depreciation and Amortization 3,048 2,993 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 11,133 10,684 OTHER NONCURRENT ASSETS Regulatory Assets 389 326 Operating Lease Assets 46 50 Deferred Charges and Other Noncurrent Assets 446 659 TOTAL OTHER NONCURRENT ASSETS 881 1,035 TOTAL ASSETS $ 12,531 $ 12,210 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 84 OHIO POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS LIABILITIES AND COMMON SHAREHOLDER’S EQUITY June 30, 2026 and December 31, 2025 (dollars in millions) (Unaudited) June 30, December 31, 2026 2025 CURRENT LIABILITIES Advances from Affiliates $ 64 $ 79 Accounts Payable: General 426 391 Affiliated Companies 194 197 Risk Management Liabilities 4 5 Customer Deposits 107 108 Accrued Taxes 663 858 Obligations Under Operating Leases 13 13 Other Current Liabilities 222 239 TOTAL CURRENT LIABILITIES 1,693 1,890 NONCURRENT LIABILITIES Long-term Debt – Nonaffiliated 3,720 3,718 Long-term Risk Management Liabilities 24 28 Deferred Income Taxes 1,359 1,268 Regulatory Liabilities and Deferred Investment Tax Credits 878 893 Obligations Under Operating Leases 33 37 Deferred Credits and Other Noncurrent Liabilities 345 225 TOTAL NONCURRENT LIABILITIES 6,359 6,169 TOTAL LIABILITIES 8,052 8,059 Rate Matters (Note 4) Commitments, Guarantees and Contingencies (Note 5) COMMON SHAREHOLDER’S EQUITY Common Stock –No Par Value: Authorized – 40,000,000 Shares Outstanding – 27,952,473 Shares 321 321 Paid-in Capital 1,134 1,030 Retained Earnings 3,024 2,800 TOTAL COMMON SHAREHOLDER’S EQUITY 4,479 4,151 TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 12,531 $ 12,210 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 85 OHIO POWER COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Six Months Ended June 30, 2026 2025 OPERATING ACTIVITIES Net Income $ 226 $ 166 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 202 189 Deferred Income Taxes 55 14 Allowance for Equity Funds Used During Construction (13) (14) Mark-to-Market of Risk Management Contracts (5) — Property Taxes 213 206 Security Deposits 114 49 Change in Regulatory Assets (50) 13 Change in Other Noncurrent Assets (40) 28 Change in Other Noncurrent Liabilities 10 (58) Changes in Certain Components of Working Capital: Accounts Receivable, Net (9) 2 Materials and Supplies (12) (19) Accounts Payable 30 (5) Customer Deposits (1) (15) Accrued Taxes, Net (186) (306) Other Current Assets 3 7 Other Current Liabilities (32) (23) Net Cash Flows from Operating Activities 505 234 INVESTING ACTIVITIES Construction Expenditures (617) (505) Change in Advances to Affiliates, Net — 115 Other Investing Activities 25 27 Net Cash Flows Used for Investing Activities (592) (363) FINANCING ACTIVITIES Capital Contribution from Parent 104 2 Change in Advances from Affiliates, Net (15) 203 Principal Payments for Finance Lease Obligations (2) (2) Dividends Paid on Common Stock — (71) Other Financing Activities — 1 Net Cash Flows from Financing Activities 87 133 Net Increase in Cash and Cash Equivalents — 4 Cash and Cash Equivalents at Beginning of Period 5 4 Cash and Cash Equivalents at End of Period $ 5 $ 8 SUPPLEMENTARY INFORMATION Cash Paid for Interest, Net of Capitalized Amounts $ 72 $ 72 Noncash Acquisitions Under Finance Leases 1 1 Construction Expenditures Included in Current Liabilities as of June 30, 140 121 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 86 PUBLIC SERVICE COMPANY OF OKLAHOMA MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS RESULTS OF OPERATIONS KWh Sales/Degree Days Summary of KWh Energy Sales Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in millions of KWhs) Retail: Residential 1,406 1,319 2,770 2,911 Commercial 1,513 1,485 2,860 2,806 Industrial 1,502 1,483 2,913 2,860 Miscellaneous 329 325 613 604 Total Retail 4,750 4,612 9,156 9,181 Wholesale (a) 17 28 54 85 Total KWhs 4,767 4,640 9,210 9,266 (a)Includes municipalities and cooperatives, unit power and other wholesale customers. Summary of Heating and Cooling Degree Days Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in degree days) Actual – Heating 1 31 761 1,193 Normal – Heating 43 43 1,092 1,081 Actual – Cooling 756 605 850 629 Normal – Cooling 705 709 726 729 87 Public Service Company of Oklahoma Reconciliation of 2025 to 2026 Net Income (in millions) Three Months Ended June 30, Six Months Ended June 30, 2025 Net Income $ 63 $ 91 Changes in Revenues: Retail Revenues (a) 59 103 Transmission Revenues (4) (4) Other Revenues (3) (2) Total Change in Revenues 52 97 Changes in Expenses and Other: Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (8) (43) Other Operation and Maintenance (26) (63) Depreciation and Amortization (7) (11) Taxes Other Than Income Taxes (2) (7) Interest Income — (2) Allowance for Equity Funds Used During Construction (1) (1) Non-Service Cost Components of Net Periodic Benefit Cost (Credit) (5) (5) Interest Expense (14) (27) Total Change in Expenses and Other (63) (159) Income Tax Benefit 2 40 2026 Net Income $ 54 $ 69 (a)Includes firm wholesale sales to municipals and cooperatives. Second Quarter of 2026 Compared to Second Quarter of 2025 The major components of the increase in Revenues were as follows: •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. These increases were partially offset by: •A $9 million decrease in weather-normalized revenues primarily in the residential class. Expenses and Other changed between years as follows: •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. These increases were partially offset by: •A $5 million decrease in 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. 88 Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 The major components of the increase in Revenues were as follows: •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. These increases were partially offset by: •A $17 million decrease in weather-normalized revenues primarily in the residential class. Expenses and Other and Income Tax Benefit changed between years as follows: •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 in transmission 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 primarily due 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. These increases were partially offset by: •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. 89 PUBLIC SERVICE COMPANY OF OKLAHOMA CONDENSED STATEMENTS OF INCOME For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 REVENUES Electric Generation, Transmission and Distribution $ 517 $ 466 $ 951 $ 856 Sales to AEP Affiliates 4 1 8 2 Other Revenues — 2 1 5 TOTAL REVENUES 521 469 960 863 EXPENSES Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 180 172 344 301 Other Operation 138 123 265 224 Maintenance 41 30 80 58 Depreciation and Amortization 74 67 147 136 Taxes Other Than Income Taxes 22 20 45 38 TOTAL EXPENSES 455 412 881 757 OPERATING INCOME 66 57 79 106 Other Income (Expense): Interest Income — — — 2 Allowance for Equity Funds Used During Construction 2 3 5 6 Non-Service Cost Components of Net Periodic Benefit Cost (Credit) (3) 2 (1) 4 Interest Expense (43) (29) (86) (59) INCOME (LOSS) BEFORE INCOME TAX EXPENSE (BENEFIT) 22 33 (3) 59 Income Tax Expense (Benefit) (32) (30) (72) (32) NET INCOME $ 54 $ 63 $ 69 $ 91 The common stock of PSO is wholly-owned by Parent. See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 90 PUBLIC SERVICE COMPANY OF OKLAHOMA CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 Net Income $ 54 $ 63 $ 69 $ 91 OTHER COMPREHENSIVE LOSS, NET OF TAXES Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively. — — — (1) TOTAL COMPREHENSIVE INCOME $ 54 $ 63 $ 69 $ 90 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 91 PUBLIC SERVICE COMPANY OF OKLAHOMA CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Common Stock Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2024 $ 157 $ 1,042 $ 1,484 $ 3 $ 2,686 Net Income 28 28 Other Comprehensive Loss (1) (1) TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2025 157 1,042 1,512 2 2,713 Capital Contribution from Parent 300 300 Net Income 63 63 TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2025 $ 157 $ 1,342 $ 1,575 $ 2 $ 3,076 TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2025 $ 157 $ 1,718 $ 1,736 $ 2 $ 3,613 Net Income 15 15 TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2026 157 1,718 1,751 2 3,628 Capital Contribution from Parent 113 113 Net Income 54 54 TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2026 $ 157 $ 1,831 $ 1,805 $ 2 $ 3,795 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 92 PUBLIC SERVICE COMPANY OF OKLAHOMA CONDENSED BALANCE SHEETS ASSETS June 30, 2026 and December 31, 2025 (in millions) (Unaudited) June 30, December 31, 2026 2025 CURRENT ASSETS Cash and Cash Equivalents $ 3 $ 2 Accounts Receivable: Customers 103 109 Affiliated Companies 125 45 Miscellaneous 13 4 Total Accounts Receivable 241 158 Fuel 3 3 Materials and Supplies 140 119 Risk Management Assets 43 42 Accrued Tax Benefits 76 8 Regulatory Asset for Under-Recovered Fuel Costs 31 37 Prepayments and Other Current Assets 26 14 TOTAL CURRENT ASSETS 563 383 PROPERTY, PLANT AND EQUIPMENT Electric: Generation 4,118 4,365 Transmission 1,506 1,433 Distribution 4,130 3,987 Other Property, Plant and Equipment 1,302 1,292 Construction Work in Progress 864 635 Total Property, Plant and Equipment 11,920 11,712 Accumulated Depreciation and Amortization 2,498 2,748 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 9,422 8,964 OTHER NONCURRENT ASSETS Regulatory Assets 693 637 Employee Benefits and Pension Assets 96 95 Operating Lease Assets 122 126 Deferred Charges and Other Noncurrent Assets 50 13 TOTAL OTHER NONCURRENT ASSETS 961 871 TOTAL ASSETS $ 10,946 $ 10,218 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 93 PUBLIC SERVICE COMPANY OF OKLAHOMA CONDENSED BALANCE SHEETS LIABILITIES AND COMMON SHAREHOLDER’S EQUITY June 30, 2026 and December 31, 2025 (in millions, except per-share and share amounts) (Unaudited) June 30, December 31, 2026 2025 CURRENT LIABILITIES Advances from Affiliates $ 394 $ 171 Accounts Payable: General 367 339 Affiliated Companies 136 87 Long-term Debt Due Within One Year – Nonaffiliated 51 51 Risk Management Liabilities 22 27 Customer Deposits 117 115 Accrued Taxes 86 37 Accrued Interest 66 67 Obligations Under Operating Leases 12 11 Other Current Liabilities 118 104 TOTAL CURRENT LIABILITIES 1,369 1,009 NONCURRENT LIABILITIES Long-term Debt – Nonaffiliated 3,476 3,475 Deferred Income Taxes 1,156 1,113 Regulatory Liabilities and Deferred Investment Tax Credits 712 717 Asset Retirement Obligations 157 136 Obligations Under Operating Leases 119 122 Deferred Credits and Other Noncurrent Liabilities 162 33 TOTAL NONCURRENT LIABILITIES 5,782 5,596 TOTAL LIABILITIES 7,151 6,605 Rate Matters (Note 4) Commitments, Guarantees and Contingencies (Note 5) COMMON SHAREHOLDER’S EQUITY Common Stock – Par Value – $15 Per Share: Authorized – 11,000,000 Shares Issued – 10,482,000 Shares Outstanding – 9,013,000 Shares 157 157 Paid-in Capital 1,831 1,718 Retained Earnings 1,805 1,736 Accumulated Other Comprehensive Income (Loss) 2 2 TOTAL COMMON SHAREHOLDER’S EQUITY 3,795 3,613 TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 10,946 $ 10,218 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 94 PUBLIC SERVICE COMPANY OF OKLAHOMA CONDENSED STATEMENTS OF CASH FLOWS For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Six Months Ended June 30, 2026 2025 OPERATING ACTIVITIES Net Income $ 69 $ 91 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 147 136 Deferred Income Taxes 34 40 Allowance for Equity Funds Used During Construction (5) (6) Mark-to-Market of Risk Management Contracts (1) (73) Property Taxes (37) (32) Deferred Fuel Over/Under-Recovery, Net 6 (74) Change in Other Regulatory Assets (6) (25) Change in Other Noncurrent Assets (26) 3 Change in Other Noncurrent Liabilities 151 (8) Changes in Certain Components of Working Capital: Accounts Receivable, Net (83) (39) Fuel, Materials and Supplies (21) 3 Accounts Payable 114 121 Accrued Taxes, Net (19) 45 Other Current Assets (11) (16) Other Current Liabilities (34) (1) Net Cash Flows from Operating Activities 278 165 INVESTING ACTIVITIES Construction Expenditures (615) (325) Change in Advances to Affiliates, Net — 232 Acquisitions of Generation Facilities — (1,359) Other Investing Activities 3 1 Net Cash Flows Used for Investing Activities (612) (1,451) FINANCING ACTIVITIES Capital Contribution from Parent 113 300 Issuance of Long-term Debt – Nonaffiliated — 794 Change in Advances from Affiliates, Net 223 320 Retirement of Long-term Debt – Nonaffiliated — (125) Other Financing Activities (1) (1) Net Cash Flows from Financing Activities 335 1,288 Net Increase in Cash and Cash Equivalents 1 2 Cash and Cash Equivalents at Beginning of Period 2 2 Cash and Cash Equivalents at End of Period $ 3 $ 4 SUPPLEMENTARY INFORMATION Cash Paid for Interest, Net of Capitalized Amounts $ 86 $ 47 Construction Expenditures Included in Current Liabilities as of June 30, 184 91 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 95 SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS RESULTS OF OPERATIONS KWh Sales/Degree Days Summary of KWh Energy Sales Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in millions of KWhs) Retail: Residential 1,416 1,365 2,847 2,968 Commercial 1,431 1,415 2,703 2,660 Industrial 1,358 1,327 2,583 2,508 Miscellaneous 17 18 33 34 Total Retail 4,222 4,125 8,166 8,170 Wholesale (a) 1,104 1,251 2,379 2,743 Total KWhs 5,326 5,376 10,545 10,913 (a)Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers. Summary of Heating and Cooling Degree Days Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in degree days) Actual – Heating 2 9 496 726 Normal – Heating 24 24 720 714 Actual – Cooling 888 948 1,038 1,044 Normal – Cooling 781 770 831 816 96 Southwestern Electric Power Company Consolidated Reconciliation of 2025 to 2026 Earnings Attributable to SWEPCo Common Shareholder (in millions) Three Months Ended June 30, Six Months Ended June 30, 2025 Earnings Attributable to Common Shareholder $ 116 $ 164 Changes in Revenues: Retail Revenues (a) 21 42 Off-system Sales 1 1 Transmission Revenues (8) 11 Other Revenues 4 4 Total Change in Revenues 18 58 Changes in Expenses and Other: Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 36 56 Other Operation and Maintenance (25) (57) Asset Impairments and Other Related Charges — (31) Depreciation and Amortization (15) (38) Taxes Other Than Income Taxes (6) (8) Interest Income (2) (2) Allowance for Equity Funds Used During Construction 3 8 Non-Service Cost Components of Net Periodic Benefit Cost — (1) Interest Expense (25) (36) Total Change in Expenses and Other (34) (109) Income Tax Benefit (14) 29 Equity Earnings of Unconsolidated Subsidiary (1) (1) Net Income Attributable to Noncontrolling Interest 1 1 2026 Earnings Attributable to Common Shareholder $ 86 $ 142 (a)Includes firm wholesale sales to municipals and cooperatives. Second Quarter of 2026 Compared to Second Quarter of 2025 The major components of the increase in Revenues were as follows: •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. These increases were partially offset by: •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. This decrease was partially offset by: •A $19 million increase due to continued transmission investment. 97 Expenses and Other and Income Tax Benefit changed between years as follows: •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. These decreases were partially offset by: •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. This decrease was partially offset by: •A $24 million increase due to an increase in PTCs. Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 The major components of the increase in Revenues were as follows: •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. These increases were partially offset by: •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. This increase was partially offset by: •A $27 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates. Expenses and Other and Income Tax Benefit changed between years as follows: •Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $56 million primarily due to 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. These decreases were partially offset by: •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 primarily due to: •A $23 million increase in SPP expenses. This increase was partially offset by: •A $10 million decrease due to the June 2025 FERC order related to the treatment of NOLC's in transmission formula rates. 98 •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. These increases were partially offset by: •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. 99 SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED CONDENSED CONSOLIDATED STATEMENTS OF INCOME For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 REVENUES Electric Generation, Transmission and Distribution $ 561 $ 545 $ 1,109 $ 1,062 Sales to AEP Affiliates 25 24 47 35 Other Revenues 2 1 3 4 TOTAL REVENUES 588 570 1,159 1,101 EXPENSES Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 156 192 327 383 Other Operation 126 108 244 205 Maintenance 57 50 103 85 Asset Impairments and Other Related Charges — — 31 — Depreciation and Amortization 123 108 244 206 Taxes Other Than Income Taxes 35 29 72 64 TOTAL EXPENSES 497 487 1,021 943 OPERATING INCOME 91 83 138 158 Other Income (Expense): Interest Income 1 3 3 5 Allowance for Equity Funds Used During Construction 7 4 15 7 Non-Service Cost Components of Net Periodic Benefit Cost 2 2 3 4 Interest Expense (59) (34) (109) (73) INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS 42 58 50 101 Income Tax Expense (Benefit) (44) (58) (93) (64) Equity Earnings of Unconsolidated Subsidiary — 1 — 1 NET INCOME 86 117 143 166 Net Income Attributable to Noncontrolling Interest — 1 1 2 EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $ 86 $ 116 $ 142 $ 164 The common stock of SWEPCo is wholly-owned by Parent. See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 100 SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the Three and Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2026 2025 2026 2025 Net Income $ 86 $ 117 $ 143 $ 166 OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively — — — — Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively — — — — TOTAL COMPREHENSIVE INCOME 86 117 143 166 Total Comprehensive Income Attributable to Noncontrolling Interest — 1 1 2 TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $ 86 $ 116 $ 142 $ 164 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 101 SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) SWEPCo Common Shareholder Common Stock Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interest Total TOTAL EQUITY – DECEMBER 31, 2024 $ — $ 1,550 $ 2,352 $ 3 $ — $ 3,905 Common Stock Dividends – Nonaffiliated (1) (1) Net Income 48 1 49 TOTAL EQUITY – MARCH 31, 2025 — 1,550 2,400 3 — 3,953 Capital Contribution from Parent 450 450 Common Stock Dividends – Nonaffiliated (1) (1) Net Income 116 1 117 TOTAL EQUITY – JUNE 30, 2025 $ — $ 2,000 $ 2,516 $ 3 $ — $ 4,519 TOTAL EQUITY – DECEMBER 31, 2025 $ — $ 2,151 $ 2,740 $ 8 $ — $ 4,899 Capital Contribution from Parent 128 128 Common Stock Dividends – Nonaffiliated (1) (1) Net Income 56 1 57 TOTAL EQUITY – MARCH 31, 2026 — 2,279 2,796 8 — 5,083 Capital Contribution from Parent 81 81 Net Income 86 — 86 TOTAL EQUITY – JUNE 30, 2026 $ — $ 2,360 $ 2,882 $ 8 $ — $ 5,250 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 102 SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED CONDENSED CONSOLIDATED BALANCE SHEETS ASSETS June 30, 2026 and December 31, 2025 (in millions) (Unaudited) June 30, December 31, 2026 2025 CURRENT ASSETS Cash and Cash Equivalents $ 2 $ 2 Restricted Cash(June 30, 2026 and December 31, 2025 Amounts Include $14 and $15, Respectively, Related to Storm Recovery Funding) 14 15 Advances to Affiliates — 23 Accounts Receivable: Customers 50 63 Affiliated Companies 116 91 Miscellaneous 11 10 Total Accounts Receivable 177 164 Fuel 91 83 Materials and Supplies (June 30, 2026 and December 31, 2025 Amounts Include $1 and $1, Respectively, Related to Sabine) 96 88 Risk Management Assets 42 35 Accrued Tax Benefits 110 17 Regulatory Asset for Under-Recovered Fuel Costs 94 115 Prepayments and Other Current Assets 15 14 TOTAL CURRENT ASSETS 641 556 PROPERTY, PLANT AND EQUIPMENT Electric: Generation 6,650 6,621 Transmission 3,397 3,302 Distribution 3,366 3,242 Other Property, Plant and Equipment (June 30, 2026 and December 31, 2025 Amounts Include $84 and $125, Respectively, Related to Sabine) 932 942 Construction Work in Progress 1,061 712 Total Property, Plant and Equipment 15,406 14,819 Accumulated Depreciation and Amortization (June 30, 2026 and December 31, 2025 Amounts Include $84 and $125, Respectively, Related to Sabine) 3,590 3,478 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 11,816 11,341 OTHER NONCURRENT ASSETS Regulatory Assets 955 903 Securitized Assets(June 30, 2026 and December 31, 2025 Amounts Include $307 and $315, Respectively, Related to Storm Recovery Funding) 307 315 Deferred Charges and Other Noncurrent Assets 465 409 TOTAL OTHER NONCURRENT ASSETS 1,727 1,627 TOTAL ASSETS $ 14,184 $ 13,524 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 103 SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED CONDENSED CONSOLIDATED BALANCE SHEETS LIABILITIES AND EQUITY June 30, 2026 and December 31, 2025 (in millions, except per-share and share amounts) (Unaudited) June 30, December 31, 2026 2025 CURRENT LIABILITIES Advances from Affiliates $ 311 $ — Accounts Payable: General 457 392 Affiliated Companies 80 89 Short-term Debt – Nonaffiliated 3 3 Long-term Debt Due Within One Year – Nonaffiliated(June 30, 2026 and December 31, 2025 Amounts Include $17 and $17, Respectively, Related to Storm Recovery Funding) 417 917 Risk Management Liabilities 10 9 Customer Deposits 84 79 Accrued Taxes 131 68 Accrued Interest 65 49 Obligations Under Operating Leases 5 7 Provision for Refund 83 81 Other Current Liabilities 173 191 TOTAL CURRENT LIABILITIES 1,819 1,885 NONCURRENT LIABILITIES Long-term Debt – Nonaffiliated(June 30, 2026 and December 31, 2025 Amounts Include $296 and $304, Respectively, Related to Storm Recovery Funding) 4,441 3,057 Long-term Debt – Affiliated — 1,000 Deferred Income Taxes 1,516 1,458 Regulatory Liabilities and Deferred Investment Tax Credits 507 531 Asset Retirement Obligations 238 252 Employee Benefits and Pension Obligations 42 39 Obligations Under Operating Leases 192 195 Provision for Refund 6 47 Storm Reserve 110 108 Deferred Credits and Other Noncurrent Liabilities 63 53 TOTAL NONCURRENT LIABILITIES 7,115 6,740 TOTAL LIABILITIES 8,934 8,625 Rate Matters (Note 4) Commitments, Guarantees and Contingencies (Note 5) EQUITY Common Stock – Par Value – $18 Per Share: Authorized – 3,680 Shares Outstanding – 3,680 Shares — — Paid-in Capital 2,360 2,151 Retained Earnings 2,882 2,740 Accumulated Other Comprehensive Income (Loss) 8 8 TOTAL COMMON SHAREHOLDER’S EQUITY 5,250 4,899 Noncontrolling Interest — — TOTAL EQUITY 5,250 4,899 TOTAL LIABILITIES AND EQUITY $ 14,184 $ 13,524 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 104 SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS For the Six Months Ended June 30, 2026 and 2025 (in millions) (Unaudited) Six Months Ended June 30, 2026 2025 OPERATING ACTIVITIES Net Income $ 143 $ 166 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 244 206 Deferred Income Taxes 26 18 Asset Impairments and Other Related Charges 31 — Allowance for Equity Funds Used During Construction (15) (7) Mark-to-Market of Risk Management Contracts (5) (51) Pension Contributions to Qualified Plan Trust — (9) Property Taxes (55) (45) Deferred Fuel Over/Under-Recovery, Net 46 64 Change in Regulatory Assets (89) (33) Change in Other Noncurrent Assets (13) 6 Change in Other Noncurrent Liabilities (42) (57) Changes in Certain Components of Working Capital: Accounts Receivable, Net (9) 8 Fuel, Materials and Supplies (16) (6) Accounts Payable 41 90 Accrued Taxes, Net (30) 32 Other Current Assets 2 (20) Other Current Liabilities (6) (4) Net Cash Flows from Operating Activities 253 358 INVESTING ACTIVITIES Construction Expenditures (692) (440) Change in Advances to Affiliates, Net 23 (76) Other Investing Activities 13 5 Net Cash Flows Used for Investing Activities (656) (511) FINANCING ACTIVITIES Capital Contribution from Parent 209 450 Issuance of Long-term Debt – Nonaffiliated 1,393 — Change in Short-term Debt – Nonaffiliated — (4) Change in Advances from Affiliates, Net 311 (275) Retirement of Long-term Debt – Nonaffiliated (508) — Retirement of Long-term Debt – Affiliated (1,000) — Dividends Paid on Common Stock – Nonaffiliated (1) (2) Other Financing Activities (2) — Net Cash Flows from Financing Activities 402 169 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash (1) 16 Cash, Cash Equivalents and Restricted Cash at Beginning of Period 17 5 Cash, Cash Equivalents and Restricted Cash at End of Period $ 16 $ 21 SUPPLEMENTARY INFORMATION Cash Paid for Interest, Net of Capitalized Amounts $ 95 $ 72 Construction Expenditures Included in Current Liabilities as of June 30, 237 99 See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106. 105 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: Note Registrant Page Number Significant Accounting Matters AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 107 New Accounting Standards AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 109 Comprehensive Income AEP 110 Rate Matters AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 112 Commitments, Guarantees and Contingencies AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 128 Acquisitions, Dispositions and Impairments AEP, AEPTCo, APCo, I&M, PSO, SWEPCo 132 Benefit Plans AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 134 Business Segments AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 137 Derivatives and Hedging AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 143 Fair Value Measurements AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 153 Income Taxes AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 167 Financing Activities AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 170 Variable Interest Entities AEP, AEP Texas, APCo, I&M, OPCo, SWEPCo 178 Property, Plant and Equipment AEP, PSO 181 Revenue from Contracts with Customers AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 182 Subsequent Events AEP 191 106 1. SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. 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: Three Months Ended June 30, 2026 2025 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 713 $ 1,226 Weighted-Average Number of Basic AEP Common Shares Outstanding 544.2 $ 1.31 534.3 $ 2.29 Weighted-Average Dilutive Effect 6.4 (0.01) 2.1 — Weighted-Average Number of Diluted AEP Common Shares Outstanding 550.6 $ 1.30 536.4 $ 2.29 Six Months Ended June 30, 2026 2025 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 1,587 $ 2,026 Weighted-Average Number of Basic AEP Common Shares Outstanding 543.1 $ 2.92 533.8 $ 3.80 Weighted-Average Dilutive Effect 5.7 (0.03) 1.7 (0.02) Weighted-Average Number of Diluted AEP Common Shares Outstanding 548.8 $ 2.89 535.5 $ 3.78 There were no antidilutive shares outstanding as of June 30, 2026 and 2025. 107 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: June 30, 2026 AEP AEP Texas APCo SWEPCo (in millions) Cash and Cash Equivalents $ 375 $ — $ 4 $ 2 Restricted Cash 72 13 25 14 Total Cash, Cash Equivalents and Restricted Cash $ 447 $ 13 $ 29 $ 16 December 31, 2025 AEP AEP Texas APCo SWEPCo (in millions) Cash and Cash Equivalents $ 197 $ — $ 5 $ 2 Restricted Cash 71 14 18 15 Total Cash, Cash Equivalents and Restricted Cash $ 268 $ 14 $ 23 $ 17 Supplementary Cash Flow Information (Applies to AEP) Six Months Ended June 30, Cash Flow Information 2026 2025 (in millions) Cash Paid for: Interest, Net of Capitalized Amounts $ 1,083 $ 946 Noncash Investing and Financing Activities: Construction Expenditures Included in Current Liabilities as of June 30, 2,005 1,059 Contribution in Aid of Construction Advances in Current Assets as of June 30, 112 — Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 33 33 108 2. NEW ACCOUNTING STANDARDS The disclosures in this note apply to all Registrants unless indicated otherwise. 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. 109 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. Cash Flow Hedges Pension Three Months Ended June 30, 2026 Commodity Interest Rate and OPEB Total (in millions) Balance in AOCI as of March 31, 2026 $ 63 $ (1) $ (40) $ 22 Change in Fair Value Recognized in AOCI, Net of Tax 20 — — 20 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a) 2 — — 2 Amortization of Actuarial (Gains) Losses — — 2 2 Reclassifications from AOCI, before Income Tax (Expense) Benefit 2 — 2 4 Income Tax (Expense) Benefit — — 1 1 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 2 — 1 3 Net Current Period Other Comprehensive Income 22 — 1 23 Balance in AOCI as of June 30, 2026 $ 85 $ (1) $ (39) $ 45 Cash Flow Hedges Pension Three Months Ended June 30, 2025 Commodity Interest Rate and OPEB Total (in millions) Balance in AOCI as of March 31, 2025 $ 124 $ 1 $ (104) $ 21 Change in Fair Value Recognized in AOCI, Net of Tax (36) — — (36) Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a) 5 — — 5 Interest Expense (a) — (1) — (1) Reclassifications from AOCI, before Income Tax (Expense) Benefit 5 (1) — 4 Income Tax (Expense) Benefit 1 — — 1 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 4 (1) — 3 Net Current Period Other Comprehensive Loss (32) (1) — (33) Balance in AOCI as of June 30, 2025 $ 92 $ — $ (104) $ (12) 110 Cash Flow Hedges Pension Six Months Ended June 30, 2026 Commodity Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2025 $ 78 $ (1) $ (41) $ 36 Change in Fair Value Recognized in AOCI, Net of Tax 45 — — 45 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a) (48) — — (48) Amortization of Actuarial (Gains) Losses — — 3 3 Reclassifications from AOCI, before Income Tax (Expense) Benefit (48) — 3 (45) Income Tax (Expense) Benefit (10) — 1 (9) Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (38) — 2 (36) Net Current Period Other Comprehensive Income 7 — 2 9 Balance in AOCI as of June 30, 2026 $ 85 $ (1) $ (39) $ 45 Cash Flow Hedges Pension Six Months Ended June 30, 2025 Commodity Interest Rate and OPEB Total (in millions) Balance in AOCI as of December 31, 2024 $ 99 $ 3 $ (105) $ (3) Change in Fair Value Recognized in AOCI, Net of Tax 2 (1) — 1 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a) (12) — — (12) Interest Expense (a) — (2) — (2) Amortization of Actuarial (Gains) Losses — — 1 1 Reclassifications from AOCI, before Income Tax Expense (12) (2) 1 (13) Income Tax Expense (3) — — (3) Reclassifications from AOCI, Net of Income Tax Expense (9) (2) 1 (10) Net Current Period Other Comprehensive Income (Loss) (7) (3) 1 (9) Balance in AOCI as of June 30, 2025 $ 92 $ — $ (104) $ (12) (a)Amounts reclassified to the referenced line item on the statements of income. 111 4. RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. 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. 112 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: Plant Net Book Value Accelerated Depreciation Regulatory Asset Cost of Removal Regulatory Liability Projected Retirement Date Current Authorized Recovery Period Annual Depreciation (a) (dollars in millions) Northeastern Plant, Unit 3 $ 53 $ 251 $ 21 (b) 2026 (c) $ 11 Welsh Plant, Units 1 and 3 230 249 55 (d) 2028 (e) (f) 44 (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. 113 Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except OPCo) AEP June 30, December 31, 2026 2025 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Welsh Plant, Units 1 and 3 Accelerated Depreciation $ 249 $ 220 UTM Deferred Costs 65 56 Pirkey Plant Accelerated Depreciation 61 93 Storm-Related Costs 47 43 System Resiliency Plan Deferred Costs - Texas 46 17 Other Regulatory Assets Pending Final Regulatory Approval 5 6 Regulatory Assets Currently Not Earning a Return Storm-Related Costs (a) 300 191 Plant Retirement Costs – Asset Retirement Obligation Costs (b) 283 257 NOLC Costs (c) 85 89 2024-2025 Virginia Biennial Under-Earnings (d) 51 172 Vegetation Management Costs 33 — Deferred Pension and OPEB Costs 36 27 Other Regulatory Assets Pending Final Regulatory Approval 165 136 Total Regulatory Assets Pending Final Regulatory Approval $ 1,426 $ 1,307 (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. AEP Texas June 30, December 31, 2026 2025 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return UTM Deferred Costs $ 65 $ 56 Storm-Related Costs 41 41 System Resiliency Plan Deferred Costs 23 17 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 39 31 Deferred Pension and OPEB Costs 36 27 UTM Deferred Costs 7 — Other Regulatory Assets Pending Final Regulatory Approval 10 9 Total Regulatory Assets Pending Final Regulatory Approval $ 221 $ 181 114 AEPTCo June 30, December 31, 2026 2025 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Income Taxes, Net $ 9 $ 9 Total Regulatory Assets Pending Final Regulatory Approval $ 9 $ 9 APCo June 30, December 31, 2026 2025 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Other Regulatory Assets Pending Final Regulatory Approval $ 2 $ 2 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs – Asset Retirement Obligation Costs (a) 185 169 Storm-Related Costs – West Virginia (b) 64 39 2024-2025 Virginia Biennial Under-Earnings (c) 51 172 Vegetation Management Costs 13 — 2026-2027 Virginia Biennial Under-Earnings 18 — Pension Settlement 16 16 Virginia Corporate Alternative Minimum Tax — 13 West Virginia Corporate Alternative Minimum Tax — 11 Other Regulatory Assets Pending Final Regulatory Approval 27 18 Total Regulatory Assets Pending Final Regulatory Approval $ 376 $ 440 (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. I&M June 30, December 31, 2026 2025 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Other Regulatory Assets Pending Final Regulatory Approval $ 4 $ 4 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs – Asset Retirement Obligation Costs (a) 81 78 Storm-Related Costs – Indiana 46 29 Other Regulatory Assets Pending Final Regulatory Approval 7 7 Total Regulatory Assets Pending Final Regulatory Approval $ 138 $ 118 (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. 115 PSO June 30, December 31, 2026 2025 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Storm-Related Costs $ 34 $ 25 Generation PBA and Delayed Retirement Deferral 26 13 Oklahoma Senate Bill 998 Deferral 24 9 NOLC Costs (a) 19 23 Plant Retirement Costs – Asset Retirement Obligation Costs (b) 12 6 Other Regulatory Assets Pending Final Regulatory Approval 1 8 Total Regulatory Assets Pending Final Regulatory Approval $ 116 $ 84 (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. SWEPCo June 30, December 31, 2026 2025 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Welsh Plant, Units 1 and 3 Accelerated Depreciation $ 249 $ 220 Pirkey Plant Accelerated Depreciation 61 93 System Resiliency Plan Deferred Costs - Texas 23 1 Income Taxes, Net 7 — Other Regulatory Assets Pending Final Regulatory Approval 5 2 Regulatory Assets Currently Not Earning a Return Storm-Related Costs - Louisiana, Texas 92 43 NOLC Costs (a) 65 66 Other Regulatory Assets Pending Final Regulatory Approval 22 20 Total Regulatory Assets Pending Final Regulatory Approval $ 524 $ 445 (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 116 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 recognized an 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 million of 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 a ten-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 117 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 the four-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 118 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: Eligible Costs Approved by the WVPSC for Securitization APCo WPCo Total (in millions) Undepreciated Utility Plant Balances of Amos, Mitchell and Mountaineer (as of December 31, 2022) $ 1,145 $ 559 $ 1,704 ENEC Under-Recovery Regulatory Assets (a) 274 319 593 Forecasted Undepreciated CCR and ELG Investments of Amos, Mitchell and Mountaineer (as of November 30, 2024) (a) 88 149 237 Deferred Storm Other Operation and Maintenance Expense Regulatory Assets (a) 155 3 158 Upfront Financing Costs (a) 10 6 16 Total $ 1,672 $ 1,036 $ 2,708 (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. 119 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 and no cost disallowance associated with the Rockport UPA with AEGCo. 120 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. 121 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. 122 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 by two 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. 123 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 a two-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 124 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 the three 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: 2021 2022 2023 2024 2025 Total (in millions) $ 78 $ 68 $ 61 $ 52 $ 49 $ 308 In January 2024, the FERC issued two orders granting formal challenges by certain unaffiliated customers related to stand-alone treatment of NOLCs in the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP. The FERC directed the AEP transmission owning subsidiaries within PJM and SPP to provide refunds with interest on all amounts collected for the 2021 rate year, and for such refunds to be reflected in the annual update for the next rate year. Accordingly, AEP transmission owning subsidiaries within PJM and SPP provided refunds for the 2021 rate year, primarily through 2025 transmission revenue requirements. AEP transmission owning subsidiaries within PJM and SPP have not been directed to make cash refunds related to 2022 through 2025 rate years. As a result of the January 2024 FERC orders, the Registrants’ balance sheets reflected a liability for the probable refund of all NOLC revenues included in transmission formula rates, with interest. 125 In February 2024, AEPSC on behalf of the AEP transmission owning subsidiaries within PJM and SPP filed requests for rehearing. In March 2024, the FERC denied AEPSC’s requests for rehearing of the January 2024 orders by operation of law and stated it may address the requests for rehearing in future orders. In March 2024, AEPSC submitted refund compliance reports to the FERC, which preserve the non-finality of the FERC’s January 2024 orders pending further proceedings on rehearing and appeal. In April 2024, AEPSC made filings with the FERC which requested that the FERC: (a) reopen the record so that the FERC may take the IRS PLRs received in April 2024 regarding the treatment of stand-alone NOLCs in ratemaking into evidence and consider them in substantive orders on rehearing and (b) stay its January 2024 orders and related compliance filings and refunds to provide time for consideration of the April 2024 IRS PLRs. In May 2024, AEPSC filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit seeking review of the FERC’s January 2024 and March 2024 decisions. In July 2024, the FERC issued orders approving AEPSC’s request to reopen the record for the limited purpose of accepting into the record the IRS PLRs and establish additional briefing procedures. In August 2024, AEPSC filed briefs with the FERC requesting the commission modify or overturn its initial orders. In June 2025, the FERC issued two orders, partially reversing its January 2024 decisions on the basis of IRS PLRs accepted into the record, and concluding that the accelerated depreciation-related NOLC adjustments should be included in rate base and should also be included in the computation of Excess ADIT regulatory liabilities to be refunded to customers. Requests for rehearing were filed by intervenors in July 2025 and were rejected by the FERC on the merits in November 2025. Intervenors have filed petitions for review of the FERC’s orders in this matter with the United States Court of Appeals for the District of Columbia Circuit. The appeals have been consolidated and briefs are expected to be filed by the various parties in the third and fourth quarters of 2026. As directed by the FERC in its June 2025 order, AEP transmission owning subsidiaries within PJM and SPP submitted compliance filings in August 2025 that revised the March 2024 refund compliance reports and permit the collection of excess refunds provided to customers, with interest, in the annual update for the 2025 rate year. In October 2025, intervenors filed comments in response to the compliance filings. In March and April 2026, the FERC approved the AEP transmission owning subsidiaries’ compliance filings related to PJM and SPP, respectively. As a result of the June 2025 FERC orders, the Registrants recognized revenues, with interest, attributable to accelerated depreciation-related NOLCs included in transmission formula rates for years 2021 through 2025 and reduced Excess ADIT regulatory liabilities. Increases in affiliated transmission expense, which correspond to affiliated transmission revenues recognized, were deferred as an increase to regulatory assets or a reduction to regulatory liabilities on the balance sheets where management expects that expense would be collected from retail customers through authorized retail jurisdiction rider mechanisms. The table below summarizes the impact to the statements of income recorded by the Registrants in the second quarter of 2025: AEP AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Total Revenues $ 270 $ 214 $ 6 $ 11 $ — $ 6 $ 27 Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (24) — (17) — — — — Other Operation 53 — 15 (6) — 19 10 Income (Loss) Before Income Tax Expense (Benefit) 241 214 8 17 — (13) 17 Income Tax Expense (Benefit) (313) (203) (21) (28) — (16) (39) Net Income 554 417 29 45 — 3 56 Net Income Attributable to Noncontrolling Interest 55 55 — — — — — Earnings Attributable to Common Shareholder $ 499 $ 362 $ 29 $ 45 $ — $ 3 $ 56 FERC 2025 PJM Transmission Formula Rate Challenge (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In March 2026, an intervenor filed a formal challenge and complaint regarding the NOLC adjustments in the 2025 annual update covering the transmission formula rates for 2024 in PJM. In July 2026, the FERC rejected and denied the formal challenge and complaint. 126 Transmission Agreement Cost Allocation Complaint (Applies to AEP, APCo, I&M and OPCo) In March 2025, the KPSC and the Attorney General of Kentucky filed a complaint at the FERC against AEPSC and the AEP East Companies challenging the manner in which costs are allocated for local transmission projects pursuant to the TA. The complaint contends that certain costs allocated to KPCo are unjust, unreasonable and provide no benefit to KPCo customers. The relief requested in the complaint includes requiring a revision to the TA so that the costs for local transmission projects remain exclusively with the retail distribution service territory where the project is located unless a specific project is granted approval to establish a different cost allocation by the state commissions. Various parties have filed comments and motions to intervene. In May 2025, AEP filed a motion to dismiss and answered the complaint. In November 2025, the FERC issued an order denying the KPSC and Attorney General of Kentucky complaint. In December 2025, the KPSC and Attorney General of Kentucky requested a rehearing of the November order denying the complaint. In January 2026, the FERC issued a notice of denial of the request for rehearing by operation of law, providing the FERC with additional time to consider and decide on the merits of the request. In February 2026, the KPSC and Attorney General of Kentucky filed a petition for review of the FERC’s orders in this matter with the United States Court of Appeals for the Sixth Circuit and in June 2026, filed their brief. Parties in the matter are expected to file briefs in the third quarter of 2026. In March 2026, the FERC again denied the complaint, continuing to find that the KPSC and Attorney General of Kentucky have not met their burden of proof. If the FERC orders a change in the way costs are allocated pursuant to the TA it could impact future net income, cash flows and financial condition. FERC Audit (Applies to all Registrant Subsidiaries) The FERC Division of Audits and Accounting initiated an audit of SWEPCo in April 2024 evaluating certain accounting and reporting requirements under various FERC regulations, including compliance with the approved terms, rates and conditions of its SPP transmission formula rate mechanism. In March 2026, the FERC issued a final audit report which included, among other things, findings and recommendations related to SWEPCo's policy for the capitalization of certain vegetation management costs. As a result of the final audit report, beginning in the first quarter of 2026, AEP will no longer capitalize the vegetation management costs identified in the FERC finding on a prospective basis. AEP's PJM and SPP transmission formula rates will provide recovery of these costs as an expense effective with the 2026 rate year. Retail ratemaking for these costs will be determined in current or future ratemaking proceedings in each jurisdiction which may allow the continued capitalization of these costs as property, plant and equipment or deferral as regulatory assets. Management is unable to predict the outcome in any current or future ratemaking proceeding. If any refund liabilities are imposed by any retail commission or any disallowances occur, it would reduce future net income and cash flows and impact financial condition. Further discussions with the FERC audit staff will be held in the second half of 2026 to finalize the resolution of all findings noted in the final audit report. If any refund liabilities are imposed by the FERC or any disallowances occur, it would reduce future net income and cash flows and impact financial condition for SWEPCo. 127 5. COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2025 Annual Report should be read in conjunction with this report. COMMITMENTS In June 2026, OPCo completed the transfer of its 4.3% ownership in OVEC to Parent and its 19.93% OVEC power participation entitlement to AGR. Parent remains responsible for the financial and other obligations of AGR under the intercompany power agreement. As a result, OPCo's remaining energy and capacity purchase contract commitments are immaterial. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third-parties unless specified below. Letters of Credit (Applies to AEP) Standby letters of credit are entered into with third-parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. In April 2026, AEP increased its $5 billion revolving credit facility to $6.5 billion and extended the due date from March 2029 to April 2031. Also, in April 2026, AEP increased its $1 billion revolving credit facility to $1.5 billion and extended the due date from March 2027 to April 2029. AEP may issue up to $1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of June 30, 2026, no letters of credit were issued under either revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under seven uncommitted facilities totaling $850 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of June 30, 2026 were as follows: Company Amount Maturity (in millions) AEP $ 535 July 2026 to June 2027 During the second quarter of 2026, AEP issued an additional $131 million of letters of credit under existing uncommitted facilities with maturity dates ranging from April 2027 to June 2027. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of June 30, 2026, there were no material liabilities recorded for any indemnifications. 128 AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf. AEPSC also conducts power purchase-and-sale activity on behalf of PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf. Master Lease Agreements (Applies to all Registrants except AEPTCo) The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed. As of June 30, 2026, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows: Company Maximum Potential Loss (in millions) AEP $ 34 AEP Texas 8 APCo 4 I&M 3 OPCo 6 PSO 3 SWEPCo 4 ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo) Federal EPA’s Revised CCR Rule In April 2024, the Federal EPA finalized revisions to the CCR Rule (Legacy CCR Rule) to expand the scope of the rule to include inactive impoundments at inactive facilities (legacy CCR surface impoundments) as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land (CCR management units). The Federal EPA is requiring that owners and operators of legacy surface impoundments comply with all of the Legacy CCR Rule requirements applicable to CCR surface impoundments at active facilities, except for the location restrictions and liner design criteria. The rule establishes compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure by May 2028. The rule requires evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. Closure may be accomplished by applying an impermeable cover system over the CCR material (closure in place) or the CCR material may be excavated and placed in a compliant landfill (closure by removal). Groundwater monitoring and other analysis will provide additional information on the planned closure method. In the second quarter of 2024, AEP evaluated the applicability of the rule to current and former plant sites and recorded a $674 million increase in ARO, based on initial cost estimates primarily reflecting compliance with the rule through closure in place and future groundwater monitoring requirements pursuant to the Legacy CCR Rule. As further groundwater monitoring and other analysis is performed, management expects to refine the assumptions and underlying cost estimates used in recording the ARO. These refinements may include, but are not limited to, changes in the expected method of closure, changes in estimated quantities of CCR at each site, the identification of new CCR management units, the Federal EPA revisions to the rule, among other items. These future changes could have a material impact on the ARO and materially reduce future net income and cash flows and further impact financial condition. In January 2026, APCo received a final order from the Virginia SCC approving the recovery of $80 million of Legacy CCR Rule regulatory assets through 2041 and concurrent recovery of ongoing depreciation and accretion expenses. AEP will continue to seek cost recovery through regulated rates in other jurisdictions, including proposal of new regulatory mechanisms for cost recovery where existing mechanisms are not applicable. The rule could have an additional, material adverse impact on net income, cash flows and financial condition if AEP cannot ultimately recover these additional costs of compliance. 129 The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials. The Registrants currently incur costs to dispose of these substances safely. For remediation processes not specifically discussed, management does not anticipate that the liabilities, if any, arising from such remediation processes would have a material effect on the financial statements. NUCLEAR CONTINGENCIES (Applies to AEP and I&M) I&M owns and operates the Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. Management has started the application process for license extensions for both units that would extend Unit 1 and Unit 2 to 2054 and 2057, respectively. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cybersecurity incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third-parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cybersecurity incident, extreme weather, wildfire related liabilities or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered through the ratemaking process, could reduce future net income and cash flows and impact financial condition. Claims for Indemnification Made by Owners of the Gavin Power Station (Applies to AEP) AEP sold the Gavin Power Station to Gavin Power LLC and Lighthouse Generation LLC in 2017. Pursuant to the PSA for that transaction, AEP maintained responsibility to complete closure of the 300 acre unlined fly ash reservoir (FAR) pond in accordance with the closure plan approved by the Ohio Environmental Protection Agency and to indemnify the purchasers for that work. In July 2021, closure work was completed by AEP. In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow another pond at the Gavin Power Station, the CCR surface impoundment, to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several assertions related to the CCR Rule, including an assertion that the closure of the FAR is noncompliant with the CCR Rule in multiple respects. The owners of the Gavin Power Station have notified AEP that they believe they are entitled to indemnification for any damages that may result from these claims, including any future enforcement or litigation resulting from any determinations of noncompliance by the Federal EPA with various aspects of the CCR Rule consistent with the Gavin Denial. The owners of the Gavin Power Station have also sought indemnification for landowner claims for property damage allegedly caused by modifications to the FAR. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. In January 2024, Gavin Power LLC filed a complaint with the United States District Court for the Southern District of Ohio, alleging various violations of the Administrative Procedure Act and asserting that the Federal EPA, through its prior inaction, has waived and is estopped from raising certain objections raised in the Gavin Denial. The complaint does not assert 130 any claims against AEP. In August 2025, the District Court granted the Federal EPA’s Motion to Dismiss the complaint and the Court dismissed the case in December 2025. Based on the information currently available, management does not believe a loss is probable and cannot determine a range of potential losses, if any, that is reasonably possible of occurring. Wholesale Generating Contracts (Applies to SWEPCo) AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments engage in generation supply contracts with certain wholesale customers as part of the normal course of business. These contracts have been entered into with various municipalities and cooperatives and are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued-up to actual costs annually. During the second quarter of 2026, SWEPCo reached agreements with certain existing wholesale customers and is in discussions with one remaining existing wholesale customer under generation supply contracts, which is expected to result in credits to these wholesale customers. While the amount ultimately payable remains subject to resolution of those discussions, SWEPCo recorded a $23 million probable credit within revenues on the statement of income for the period ended June 30, 2026. 131 6. ACQUISITIONS, DISPOSITIONS AND IMPAIRMENTS The disclosures in this note apply to AEP unless indicated otherwise. ACQUISITIONS Grover Hill Wind Project (Applies to AEP and APCo) In May 2026, APCo completed the acquisition of 100% of the equity interests in Grover Hill Wind, LLC, the owner of the Grover Hill wind facility located in Paulding County, Ohio. This facility, placed in service in May 2026, serves both retail and wholesale customers in Virginia and West Virginia. The Virginia and West Virginia jurisdictional shares of the Grover Hill revenue requirement, net of PTC benefits, are recoverable through existing riders until the amounts are reflected in base rates. The acquisition of Grover Hill resulted in the recognition of operating leases for easement and access rights to the land on which the facility is located, as well as the associated ARO. In accordance with the guidance for “Business Combinations,” management determined the acquisition represented an asset acquisition. The table below summarizes the impact at acquisition on APCo’s balance sheets: Plant Name State Fuel Type Net Maximum Capacity Property, Plant and Equipment, Net Operating Lease Assets Asset Retirement Obligations (MWs) (in millions) Grover Hill OH Wind 143 $ 361 $ 8 $ 1 Oregon Clean Energy Center (Applies to AEP and I&M) In March 2026, I&M completed the acquisition of 100% of the equity interests in Oregon Clean Energy, LLC, the owner of the Oregon Clean Energy Center (Oregon Plant), a natural gas-powered, combined-cycle electric generation facility located in Oregon, Ohio. The Oregon Plant began commercial operations in 2017. I&M acquired the Oregon Plant to provide capacity and energy to both I&M Indiana and FERC jurisdictional customers. As approved by the IURC in November 2025 and prior to incorporation into the development of Indiana base rates, I&M reflects costs associated with the Oregon Plant either as eligible costs for recovery through existing I&M Indiana riders or in I&M’s ongoing Indiana earnings test evaluation. In accordance with the guidance for “Business Combinations,” management determined the acquisition of the Oregon Plant represented an asset acquisition. An asset acquisition is accounted for using a cost accumulation model with the cost of the acquisition allocated to the acquired assets and assumed liabilities based on their relative fair value. The table below summarizes the impact at acquisition on I&M’s balance sheets: Plant Name Fuel Type Net Maximum Capacity Property, Plant and Equipment, Net Prepayments and Other Current Assets Materials and Supplies Accounts Receivable Accounts Payable (MWs) (in millions) Oregon Plant Natural Gas 870 $ 918 $ 35 $ 5 $ 16 $ 9 Pixley Solar Energy Facility, Flat Ridge IV Wind Energy Facility and Green Country Power Plant (Applies to AEP and PSO) In May 2025, PSO acquired 100% of the equity interests in Pixley Solar Energy, LLC, the owner of the newly constructed Pixley solar energy facility in Barber County, Kansas. The Pixley facility, placed in service in May 2025, serves both retail and wholesale customers in Oklahoma. PSO’s revenue requirement is recoverable through an authorized rider until it is incorporated into base rates. Regulatory approval of Pixley’s output in retail rates included capital cost, performance and other guarantees, which may subject PSO to future regulatory liabilities. In June 2025, PSO also acquired 100% of the equity interests in Flat Ridge IV Wind, LLC, the owner of the newly constructed Flat Ridge IV Wind Energy Facility located in Kingman and Harper Counties, Kansas. This facility, also placed in service in June 2025, serves both retail and wholesale customers under similar recovery and regulatory provisions as the Pixley facility. The acquisitions of Pixley and Flat Ridge IV also resulted in the recognition of operating leases for easement and access rights to the land on which the facilities are located, as well as the associated ARO. In accordance with the guidance for “Business Combinations,” management determined the acquisitions of Pixley and Flat Ridge IV represented asset acquisitions. 132 Additionally, in June 2025, PSO completed the acquisition of 100% of the equity interests in Green Country Energy, LLC, the owner of a combined-cycle natural gas facility located in Jenks, Oklahoma, following approvals from both the FERC and the OCC. The transaction included the acquisition of a previously executed capacity sales agreement between Green Country Energy, LLC, as seller, and SWEPCo, as purchaser. Since July 2025, PSO sells a portion of Green Country’s capacity to SWEPCo, and this arrangement will continue through May 2027, when the agreement ends. The acquisition also resulted in the extinguishment of a previously executed capacity sales agreement between Green Country Energy, LLC, as seller, and PSO, as purchaser. In accordance with the guidance for “Business Combinations,” management determined the acquisition of Green Country represented an asset acquisition. Asset acquisitions are accounted for using a cost accumulation model, with the cost of the acquisition allocated to the acquired assets and assumed liabilities based on their relative fair value. The liabilities recognized for the capacity sales agreements will reduce PSO’s revenue requirement to recover its overall investment in Green Country, which is recoverable through a rider authorized by the OCC until it is included in base rates for the depreciable life of the facility. Management elected the income approach for its nonrecurring valuation of both the intangible liability and regulatory liability. Specifically, management applied a discounted cash flow model based on a forward market price assumption. In the first half of 2025, PSO expanded its generation portfolio by acquiring three electric generation facilities for an aggregate purchase price of $1.4 billion. The table below summarizes the impact at acquisition on PSO’s balance sheets: Plant Name State Fuel Type Net Maximum Capacity (MWs) Property, Plant and Equipment, Net Operating Lease Assets Asset Retirement Obligations Other Liabilities (in millions) Pixley KS Solar 189 $ 380 $ 9 $ 12 $ — Flat Ridge IV KS Wind 135 305 7 3 — Green Country OK Natural Gas 904 819 — — 91 (a) Total 1,228 $ 1,504 $ 16 $ 15 $ 91 (a)$50 million included in Regulatory Liabilities and Deferred Investment Tax Credits, $21 million included in Other Current Liabilities and $20 million included in Deferred Credits and Other Noncurrent Liabilities on PSO’s balance sheets. DISPOSITIONS Noncontrolling Interest in Midwest Transmission Holdings (Applies to AEP and AEPTCo) In January 2025, AEP announced a partnership whereby a nonaffiliated entity would acquire a 19.9% noncontrolling interest in Midwest Transmission Holdings, a subsidiary of AEPTCo Parent that owns all of the issued and outstanding stock of OHTCo and IMTCo. The partnership was structured pursuant to a contribution agreement between AEPTCo, along with Midwest Transmission Holdings, and Olympus BidCo L.P. (“the Investor”), a special purpose entity controlled by (a) investment funds managed by or affiliated with Kohlberg Kravis Roberts & Co. L.P. and (b) Public Sector Pension Investment Board, whereby the Investor agreed to acquire a 19.9% noncontrolling equity interest in Midwest Transmission Holdings for $2.82 billion. The transaction closed in June 2025. IMPAIRMENTS 2025 Texas Base Rate Case (Applies to AEP and SWEPCo) During the first quarter of 2026, SWEPCo recorded a pretax disallowance of $31 million in Asset Impairments and Other Related Charges on the statements of income due to a probable, partial regulatory disallowance of recovery of the Pirkey Plant net book value in the 2025 Texas Base Rate Case. See the “2025 Texas Base Rate Case” section of Note 4 for additional information. 133 7. BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo. AEPSC sponsors a qualified pension plan and two unfunded non-qualified pension plans. Substantially all AEP subsidiary employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. AEPSC also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost (Credit) Pension Plans Three Months Ended June 30, 2026 AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Service Cost $ 26 $ 3 $ 3 $ 2 $ 3 $ 1 $ 3 Interest Cost 52 4 6 6 4 2 3 Expected Return on Plan Assets (63) (5) (8) (8) (7) (3) (3) Amortization of Net Actuarial Loss 11 1 1 1 1 1 — Settlements (a) 4 (4) — — — 4 — Net Periodic Benefit Cost (Credit) $ 30 $ (1) $ 2 $ 1 $ 1 $ 5 $ 3 Three Months Ended June 30, 2025 AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Service Cost $ 24 $ 2 $ 2 $ 2 $ 3 $ 2 $ 2 Interest Cost 53 4 7 7 4 2 3 Expected Return on Plan Assets (71) (5) (10) (10) (8) (3) (3) Amortization of Net Actuarial Loss 4 1 — 1 1 — — Net Periodic Benefit Cost (Credit) $ 10 $ 2 $ (1) $ — $ — $ 1 $ 2 Six Months Ended June 30, 2026 AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Service Cost $ 51 $ 5 $ 5 $ 5 $ 5 $ 3 $ 5 Interest Cost 103 8 12 12 9 5 6 Expected Return on Plan Assets (128) (10) (16) (16) (13) (7) (7) Amortization of Net Actuarial Loss 21 2 2 2 2 1 1 Settlements (a) (7) (8) — — (6) 4 — Net Periodic Benefit Cost (Credit) $ 40 $ (3) $ 3 $ 3 $ (3) $ 6 $ 5 Six Months Ended June 30, 2025 AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Service Cost $ 48 $ 4 $ 4 $ 5 $ 5 $ 3 $ 4 Interest Cost 106 9 13 13 9 5 6 Expected Return on Plan Assets (141) (11) (19) (19) (15) (7) (7) Amortization of Net Actuarial Loss 8 1 1 1 1 — — Net Periodic Benefit Cost (Credit) $ 21 $ 3 $ (1) $ — $ — $ 1 $ 3 (a)Represents deferrals of regulatory activity. 134 OPEB Three Months Ended June 30, 2026 AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Service Cost $ 1 $ — $ — $ — $ — $ — $ — Interest Cost 7 — 1 1 1 1 — Expected Return on Plan Assets (30) (2) (4) (3) (2) (2) (2) Amortization of Prior Service Credit — — — — — — — Amortization of Net Actuarial Gain — — — — — — — Net Periodic Benefit Credit $ (22) $ (2) $ (3) $ (2) $ (1) $ (1) $ (2) Three Months Ended June 30, 2025 AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Service Cost $ 1 $ 1 $ — $ — $ — $ — $ — Interest Cost 9 — 2 1 1 1 — Expected Return on Plan Assets (28) (2) (5) (4) (3) (2) (2) Amortization of Prior Service Credit (1) — — — — — — Net Periodic Benefit Credit $ (19) $ (1) $ (3) $ (3) $ (2) $ (1) $ (2) Six Months Ended June 30, 2026 AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Service Cost $ 2 $ — $ — $ — $ — $ — $ — Interest Cost 15 1 2 2 1 1 1 Expected Return on Plan Assets (59) (5) (8) (7) (5) (3) (4) Amortization of Prior Service Credit (1) — — — — — — Amortization of Net Actuarial Gain (1) — — — — — — Net Periodic Benefit Credit $ (44) $ (4) $ (6) $ (5) $ (4) $ (2) $ (3) Six Months Ended June 30, 2025 AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Service Cost $ 2 $ 1 $ — $ — $ — $ — $ — Interest Cost 17 1 3 2 2 1 1 Expected Return on Plan Assets (56) (5) (9) (7) (6) (3) (4) Amortization of Prior Service Credit (1) — — — — — — Amortization of Net Actuarial Loss (1) — — — — — — Net Periodic Benefit Credit $ (39) $ (3) $ (6) $ (5) $ (4) $ (2) $ (3) 135 Qualified Pension Contribution (Applies to all Registrants except AEPTCo and OPCo) For the qualified pension plan, discretionary contributions may be made to maintain the funded status of the plan. In the second quarter of 2025, AEP made a discretionary contribution to the qualified pension plan. The following table provides details of the contribution by Registrant: Company Qualified Pension Plan (in millions) AEP $ 95 AEP Texas 12 APCo — I&M 2 PSO 1 SWEPCo 9 136 8. BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight applicable to each public utility subsidiary. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. The CODM of AEP is the President and CEO of AEP, who makes operating decisions, allocates resources to and assesses performance based on these reportable segments. The CODM uses earnings (loss) attributable to AEP common shareholders (presented on a GAAP basis) as a measure of segment profit or loss in making these decisions. Earnings (loss) attributable to AEP common shareholders includes intercompany revenues and expenses that are eliminated on the consolidated financial statements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities •Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities •Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo. •OPCo purchases energy and capacity to serve standard service offer customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco •Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved ROEs. •Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ROEs. Generation & Marketing •Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP. •Competitive generation in PJM. The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, income tax expense and other nonallocated costs. 137 The tables below represent AEP’s reportable segment income statement information for the three and six months ended June 30, 2026 and 2025 and reportable segment balance sheet information as of June 30, 2026 and December 31, 2025. The significant expenses disclosed below align with the segment-level information that is regularly provided to the CODM. Three Months Ended June 30, 2026 VIU T&D AEPTHCo G&M Total Reportable Segments Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 3,050 $ 1,568 $ 129 $ 693 $ 5,440 $ 5 $ — $ 5,445 Other Operating Segments 70 15 481 16 582 25 (607) (b) — Total Revenues 3,120 1,583 610 709 6,022 30 (607) 5,445 Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 900 187 — 588 1,675 — (72) 1,603 Other Operation and Maintenance 1,055 655 57 6 1,773 27 (542) 1,258 Depreciation and Amortization 569 210 130 5 914 (4) — 910 Taxes Other Than Income Taxes 143 190 87 — 420 — 7 427 Allowance for Equity Funds Used During Construction 21 28 26 — 75 — — 75 Interest Expense 264 117 68 2 451 170 (36) 585 Income Tax Expense (Benefit) (64) 37 63 29 65 (13) — 52 Equity Earnings of Unconsolidated Subsidiaries 1 — 24 — 25 4 — 29 Other Segment Items (c) (9) (7) 30 (18) (4) (31) 36 1 Earnings (Loss) Attributable to AEP Common Shareholders $ 284 $ 222 $ 225 $ 97 $ 828 $ (115) $ — $ 713 Gross Property Additions $ 1,465 $ 1,004 $ 471 $ 74 $ 3,014 $ 136 $ (24) $ 3,126 Three Months Ended June 30, 2025 VIU T&D AEPTHCo G&M Total Reportable Segments Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,934 $ 1,443 $ 155 $ 552 $ 5,084 $ 3 $ — $ 5,087 Other Operating Segments 81 6 602 14 703 27 (730) (b) — Total Revenues 3,015 1,449 757 566 5,787 30 (730) 5,087 Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 921 203 — 493 1,617 — (76) 1,541 Other Operation and Maintenance 981 541 46 — 1,568 20 (660) 928 Depreciation and Amortization 532 201 121 5 859 (5) — 854 Taxes Other Than Income Taxes 122 159 78 — 359 — 6 365 Allowance for Equity Funds Used During Construction 16 19 22 — 57 — — 57 Interest Expense 202 99 59 2 362 151 (24) 489 Income Tax Expense (Benefit) (137) 51 (139) 18 (207) (44) — (251) Equity Earnings (Loss) of Unconsolidated Subsidiaries 1 — 22 — 23 (2) — 21 Other Segment Items (c) (22) (10) 58 (14) 12 (23) 24 13 Earnings (Loss) Attributable to AEP Common Shareholders $ 433 $ 224 $ 578 $ 62 $ 1,297 $ (71) $ — $ 1,226 Gross Property Additions $ 2,232 $ 664 $ 384 $ 3 $ 3,283 $ 6 $ (10) $ 3,279 138 Six Months Ended June 30, 2026 VIU T&D AEPTHCo G&M Total Reportable Segments Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,415 $ 3,162 $ 256 $ 1,624 $ 11,457 $ 8 $ — $ 11,465 Other Operating Segments 145 30 952 37 1,164 53 (1,217) (b) — Total Revenues 6,560 3,192 1,208 1,661 12,621 61 (1,217) 11,465 Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 1,975 458 — 1,442 3,875 — (154) 3,721 Other Operation and Maintenance 2,072 1,235 110 15 3,432 65 (1,078) 2,419 Asset Impairments and Other Related Charges 31 — — — 31 — — 31 Depreciation and Amortization 1,128 427 261 10 1,826 (9) — 1,817 Taxes Other Than Income Taxes 287 390 177 1 855 — 15 870 Allowance for Equity Funds Used During Construction 44 53 48 — 145 — — 145 Interest Expense 509 222 137 3 871 336 (70) 1,137 Income Tax Expense (Benefit) (112) 77 130 51 146 (50) — 96 Equity Earnings of Unconsolidated Subsidiaries 1 — 49 — 50 4 — 54 Other Segment Items (c) (31) (23) 56 (33) (31) (53) 70 (14) Earnings (Loss) Attributable to AEP Common Shareholders $ 746 $ 459 $ 434 $ 172 $ 1,811 $ (224) $ — $ 1,587 Gross Property Additions $ 3,608 $ 2,065 $ 904 $ 79 $ 6,656 $ 283 $ (18) $ 6,921 Six Months Ended June 30, 2025 VIU T&D AEPTHCo G&M Total Reportable Segments Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,020 $ 2,958 $ 271 $ 1,282 $ 10,531 $ 19 $ — $ 10,550 Other Operating Segments 133 18 1,028 31 1,210 55 (1,265) (b) — Total Revenues 6,153 2,976 1,299 1,313 11,741 74 (1,265) 10,550 Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 1,996 466 — 1,076 3,538 — (144) 3,394 Other Operation and Maintenance 1,865 1,118 83 30 3,096 36 (1,133) 1,999 Depreciation and Amortization 1,047 404 237 9 1,697 (10) — 1,687 Taxes Other Than Income Taxes 256 364 153 1 774 1 12 787 Allowance for Equity Funds Used During Construction 32 38 44 — 114 — — 114 Interest Expense 402 211 116 4 733 298 (47) 984 Income Tax Expense (Benefit) (92) 85 (72) 54 (25) (101) — (126) Equity Earnings of Unconsolidated Subsidiaries 1 1 46 — 48 11 — 59 Other Segment Items (c) (45) (22) 59 (25) (33) (42) 47 (28) Earnings (Loss) Attributable to AEP Common Shareholders $ 757 $ 389 $ 813 $ 164 $ 2,123 $ (97) $ — $ 2,026 Gross Property Additions $ 3,153 $ 1,368 $ 814 $ 7 $ 5,342 $ 36 $ 1 $ 5,379 139 June 30, 2026 VIU T&D AEPTHCo G&M Total Reportable Segments Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Total Assets $ 65,606 $ 30,878 $ 20,832 $ 2,938 $ 120,254 $ 7,092 (d) $ (5,776) (e) $ 121,570 Investments in Equity Method Investees $ 9 $ 2 $ 1,091 $ — $ 1,102 $ 230 $ — $ 1,332 December 31, 2025 VIU T&D AEPTHCo G&M Total Reportable Segments Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Total Assets $ 61,778 $ 29,272 $ 19,719 $ 2,003 $ 112,772 $ 6,733 (d) $ (5,045) (e) $ 114,460 Investments in Equity Method Investees $ 9 $ 4 $ 1,068 $ — $ 1,081 $ 171 $ — $ 1,252 (a)Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, income tax expense and other nonallocated costs. (b)Represents inter-segment revenues. (c)Other segment items included in segment earnings (loss) attributable to AEP common shareholders primarily includes Interest and Dividend Income, Non-Service Cost Components of Net Periodic Benefit Cost and Net Income (Loss) Attributable to Noncontrolling Interests. (d)Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies. (e)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable. Registrant Subsidiaries’ Reportable Segments (Applies to all Registrant Subsidiaries except AEPTCo) The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an integrated electricity transmission and distribution business for AEP Texas and OPCo. Other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. The CODM of each Registrant Subsidiary is the AEP President and CEO, who makes operating decisions, allocates resources to and assesses performance based on these reportable segments. The CODM uses earnings (loss) attributable to common shareholders and net income (loss) that is reported on the Registrant Subsidiaries’ statements of income as a measure of segment profit or loss in making these decisions. Earnings (loss) attributable to common shareholders and net income (loss) include intercompany revenues and expenses that are eliminated on the consolidated financial statements. The expenses disclosed on the Registrant Subsidiaries’ statements of income align with the segment-level significant expenses that are regularly provided to the CODM. Total Assets is reported on the consolidated financial statements. Gross Property Additions for the Registrant Subsidiaries is represented by the sum of Construction Expenditures and Acquisition of Assets on the consolidated financial statements. See Registrant Subsidiaries statements of income, balance sheets and cash flows for details. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities. The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos’ business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for ratemaking purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. The CODM of AEPTCo is the AEP President and CEO, who makes operating decisions, allocates resources to and assesses performance based on these operating segments. The CODM uses earnings (loss) attributable to AEPTCo common shareholders (presented on a GAAP basis) as a measure of segment profit or loss in making these decisions. Earnings (loss) attributable to AEPTCo common shareholders includes intercompany revenues and expenses that are eliminated on the consolidated financial statements. The State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one reportable segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. 140 The tables below present AEPTCo’s reportable segment income statement information for the three and six months ended June 30, 2026 and 2025 and reportable segment balance sheet information as of June 30, 2026 and December 31, 2025. The significant expenses disclosed below align with the segment-level information that is regularly provided to the CODM. Three Months Ended June 30, 2026 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 107 $ — $ — $ 107 Sales to AEP Affiliates 474 — — 474 Other Revenues 7 — — 7 Total Revenues 588 — — 588 Other Operation and Maintenance 53 — — 53 Depreciation and Amortization 128 — — 128 Taxes Other Than Income Taxes 86 — — 86 Interest Income — 73 (71) (a) 2 Allowance for Equity Funds Used During Construction 26 — — 26 Interest Expense 63 72 (71) (a) 64 Income Tax Expense 62 — — 62 Other Segment Items (b) — 31 — 31 Earnings (Loss) Attributable to AEPTCo Common Shareholders $ 222 $ (30) (c) $ — $ 192 Gross Property Additions $ 462 $ — $ — $ 462 Three Months Ended June 30, 2025 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 145 $ — $ — $ 145 Sales to AEP Affiliates 597 — — 597 Total Revenues 742 — — 742 Other Operation and Maintenance 42 — — 42 Depreciation and Amortization 119 — — 119 Taxes Other Than Income Taxes 76 — — 76 Interest Income 1 84 (83) (a) 2 Allowance for Equity Funds Used During Construction 21 — — 21 Interest Expense 77 63 (83) (a) 57 Income Tax Expense (Benefit) (156) 10 — (146) Other Segment Items (b) — 61 — 61 Earnings (Loss) Attributable to AEPTCo Common Shareholders $ 606 $ (50) (c) $ — $ 556 Gross Property Additions $ 365 $ — $ — $ 365 141 Six Months Ended June 30, 2026 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 217 $ — $ — $ 217 Sales to AEP Affiliates 942 — — 942 Other Revenues 7 — — 7 Total Revenues 1,166 — — 1,166 Other Operation and Maintenance 104 — — 104 Depreciation and Amortization 256 — — 256 Taxes Other Than Income Taxes 174 — — 174 Interest Income 1 146 (143) (a) 4 Allowance for Equity Funds Used During Construction 48 — — 48 Interest Expense 128 144 (143) (a) 129 Income Tax Expense 122 — — 122 Other Segment Items (b) — 58 — 58 Earnings (Loss) Attributable to AEPTCo Common Shareholders $ 431 $ (56) (c) $ — $ 375 Gross Property Additions $ 865 $ — $ — $ 865 Six Months Ended June 30, 2025 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 249 $ — $ — $ 249 Sales to AEP Affiliates 1,020 — — 1,020 Total Revenues 1,269 — — 1,269 Other Operation and Maintenance 76 — — 76 Depreciation and Amortization 233 — — 233 Taxes Other Than Income Taxes 150 — — 150 Interest Income 1 173 (172) (a) 2 Allowance for Equity Funds Used During Construction 43 — — 43 Interest Expense 161 123 (172) (a) 112 Income Tax Expense (Benefit) (95) 10 — (85) Other Segment Items (b) — 61 — 61 Earnings (Loss) Attributable to AEPTCo Common Shareholders $ 788 $ (21) (c) $ — $ 767 Gross Property Additions $ 787 $ — $ — $ 787 June 30, 2026 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Total Assets $ 19,024 $ 7,252 (d) $ (7,200) (e) $ 19,076 December 31, 2025 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Total Assets $ 17,983 $ 6,766 (d) $ (6,750) (e) $ 17,999 (a)Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b)Other segment items included in segment earnings (loss) attributable to AEPTCo common shareholders primarily includes Net Income (Loss) Attributable to Noncontrolling Interests. (c)Includes elimination of AEPTCo Parent’s equity earnings in the State Transcos. (d)Primarily relates to Notes Receivable from the State Transcos. (e)Primarily relates to elimination of Notes Receivable from the State Transcos. 142 9. DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors of AEP. The following table represents the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments June 30, 2026 December 31, 2025 Primary Risk Exposure AEP AEP Texas APCo I&M OPCo PSO SWEPCo AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power (MWhs) 371 — 44 23 2 6 6 327 — 23 8 2 8 6 Natural Gas (MMBtus) 181 — 46 — — 53 24 166 — 48 — — 44 26 Heating Oil and Gasoline (Gallons) 7 1 1 2 1 1 1 8 2 1 2 1 1 1 Interest Rate (USD) $ 46 $ — $ — $ — $ — $ — $ — $ 40 $ — $ — $ — $ — $ — $ — Interest Rate on Long-term Debt (USD) $ 500 $ — $ — $ — $ — $ — $ — $ 500 $ — $ — $ — $ — $ — $ — 143 Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating-rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risks. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $105 million and $83 million as of June 30, 2026 and December 31, 2025, respectively. The amount of cash collateral received from third-parties netted against short-term and long-term risk management assets was not material for the Registrant Subsidiaries as of June 30, 2026. There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of December 31, 2025. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was not material for the Registrants as of June 30, 2026 and December 31, 2025. 144 Location and Fair Value of Derivative Assets and Liabilities Recognized On the Balance Sheet The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets. The derivative instruments are disclosed as gross. They are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” Unless shown as a separate line on the balance sheets due to materiality, Current Risk Management Assets are included in Prepayments and Other Current Assets, Long-term Risk Management Assets are included in Deferred Charges and Other Noncurrent Assets, Current Risk Management Liabilities are included in Other Current Liabilities and Long-term Risk Management Liabilities are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. June 30, 2026 AEP AEP Texas APCo I&M OPCo PSO SWEPCo Assets: (in millions) Current Risk Management Assets Risk Management Contracts - Commodity $ 1,296 $ 1 $ 175 $ 58 $ 1 $ 44 $ 43 Hedging Contracts - Commodity 78 — — — — — — Total Current Risk Management Assets 1,374 1 175 58 1 44 43 Long-term Risk Management Assets Risk Management Contracts - Commodity 568 — — 2 — — — Hedging Contracts - Commodity 57 — — — — — — Total Long-term Risk Management Assets 625 — — 2 — — — Total Assets $ 1,999 $ 1 $ 175 $ 60 $ 1 $ 44 $ 43 Liabilities: Current Risk Management Liabilities Risk Management Contracts - Commodity $ 914 $ — $ 14 $ 41 $ 4 $ 23 $ 10 Hedging Contracts - Commodity 15 — — — — — — Hedging Contracts - Interest Rate 17 — — — — — — Total Current Risk Management Liabilities 946 — 14 41 4 23 10 Long-term Risk Management Liabilities Risk Management Contracts - Commodity 489 — 2 3 24 6 3 Hedging Contracts - Commodity 13 — — — — — — Hedging Contracts - Interest Rate 10 — — — — — — Total Long-term Risk Management Liabilities 512 — 2 3 24 6 3 Total Liabilities $ 1,458 $ — $ 16 $ 44 $ 28 $ 29 $ 13 Total MTM Derivative Contract Net Assets (Liabilities) Recognized $ 541 $ 1 $ 159 $ 16 $ (27) $ 15 $ 30 145 December 31, 2025 AEP AEP Texas APCo I&M OPCo PSO SWEPCo Assets: (in millions) Current Risk Management Assets Risk Management Contracts - Commodity $ 720 $ — $ 82 $ 23 $ — $ 44 $ 37 Hedging Contracts - Commodity 56 — — — — — — Total Current Risk Management Assets 776 — 82 23 — 44 37 Long-term Risk Management Assets Risk Management Contracts - Commodity 518 — 2 1 — — — Hedging Contracts - Commodity 63 — — — — — — Total Long-term Risk Management Assets 581 — 2 1 — — — Total Assets $ 1,357 $ — $ 84 $ 24 $ — $ 44 $ 37 Liabilities: Current Risk Management Liabilities Risk Management Contracts - Commodity $ 500 $ — $ 5 $ 13 $ 5 $ 29 $ 11 Hedging Contracts - Commodity 16 — — — — — — Hedging Contracts - Interest Rate 16 — — — — — — Total Current Risk Management Liabilities 532 — 5 13 5 29 11 Long-term Risk Management Liabilities Risk Management Contracts - Commodity 420 — 1 1 28 1 2 Hedging Contracts - Commodity 5 — — — — — — Hedging Contracts - Interest Rate 13 — — — — — — Total Long-term Risk Management Liabilities 438 — 1 1 28 1 2 Total Liabilities $ 970 $ — $ 6 $ 14 $ 33 $ 30 $ 13 Total MTM Derivative Contract Net Assets (Liabilities) Recognized $ 387 $ — $ 78 $ 10 $ (33) $ 14 $ 24 146 Offsetting Assets and Liabilities The following tables show the net amounts of assets and liabilities presented on the balance sheets. The gross amounts offset include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with accounting guidance for “Derivatives and Hedging.” All derivative contracts subject to a master netting arrangement or similar agreement are offset on the balance sheets. June 30, 2026 AEP AEP Texas APCo I&M OPCo PSO SWEPCo Assets: (in millions) Current Risk Management Assets Gross Amounts Recognized $ 1,374 $ 1 $ 175 $ 58 $ 1 $ 44 $ 43 Gross Amounts Offset (841) (1) (4) (36) (1) (1) (1) Net Amounts Presented 533 — 171 22 — 43 42 Long-term Risk Management Assets Gross Amounts Recognized 625 — — 2 — — — Gross Amounts Offset (390) — — (2) — — — Net Amounts Presented 235 — — — — — — Total Assets $ 768 $ — $ 171 $ 22 $ — $ 43 $ 42 Liabilities: Current Risk Management Liabilities Gross Amounts Recognized $ 946 $ — $ 14 $ 41 $ 4 $ 23 $ 10 Gross Amounts Offset (794) — (4) (41) — (1) — Net Amounts Presented 152 — 10 — 4 22 10 Long-term Risk Management Liabilities Gross Amounts Recognized 512 — 2 3 24 6 3 Gross Amounts Offset (337) — — (3) — — — Net Amounts Presented 175 — 2 — 24 6 3 Total Liabilities $ 327 $ — $ 12 $ — $ 28 $ 28 $ 13 Total MTM Derivative Contract Net Assets (Liabilities) $ 441 $ — $ 159 $ 22 $ (28) $ 15 $ 29 December 31, 2025 AEP AEP Texas APCo I&M OPCo PSO SWEPCo Assets: (in millions) Current Risk Management Assets Gross Amounts Recognized $ 776 $ — $ 82 $ 23 $ — $ 44 $ 37 Gross Amounts Offset (424) — (1) (13) — (2) (2) Net Amounts Presented 352 — 81 10 — 42 35 Long-term Risk Management Assets Gross Amounts Recognized 581 — 2 1 — — — Gross Amounts Offset (316) — (1) (1) — — — Net Amounts Presented 265 — 1 — — — — Total Assets $ 617 $ — $ 82 $ 10 $ — $ 42 $ 35 Liabilities: Current Risk Management Liabilities Gross Amounts Recognized $ 532 $ — $ 5 $ 13 $ 5 $ 29 $ 11 Gross Amounts Offset (400) — (2) (13) — (2) (2) Net Amounts Presented 132 — 3 — 5 27 9 Long-term Risk Management Liabilities Gross Amounts Recognized 438 — 1 1 28 1 2 Gross Amounts Offset (260) — (1) (1) — — — Net Amounts Presented 178 — — — 28 1 2 Total Liabilities $ 310 $ — $ 3 $ — $ 33 $ 28 $ 11 Total MTM Derivative Contract Net Assets (Liabilities) $ 307 $ — $ 79 $ 10 $ (33) $ 14 $ 24 147 The tables below present the Registrants’ amount of gain (loss) recognized on risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts Three Months Ended June 30, 2026 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 1 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 11 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 1 1 — — — Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 4 — 4 — — — — Other Operation 2 — — — — — — Maintenance 2 1 1 — 1 — — Regulatory Assets (a) 8 — 3 — 3 4 (1) Regulatory Liabilities (a) 167 (1) 55 7 — 39 46 Total Gain on Risk Management Contracts $ 195 $ — $ 64 $ 8 $ 4 $ 43 $ 45 Three Months Ended June 30, 2025 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 12 $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues (13) — — — — — — Electric Generation, Transmission and Distribution Revenues — — — 12 — — — Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 1 — 1 — — — — Regulatory Assets (a) (6) — — (1) 3 (6) (3) Regulatory Liabilities (a) 77 — 3 4 3 29 41 Total Gain on Risk Management Contracts $ 71 $ — $ 4 $ 15 $ 6 $ 23 $ 38 Six Months Ended June 30, 2026 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ (29) $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 110 — — — — — — Electric Generation, Transmission and Distribution Revenues — — 1 (30) — — — Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 13 — 13 — — — — Other Operation 2 — — — — — — Maintenance 2 1 1 — 1 — — Regulatory Assets (a) 2 — — — 5 1 (4) Regulatory Liabilities (a) 348 1 158 14 3 74 56 Total Gain (Loss) on Risk Management Contracts $ 448 $ 2 $ 173 $ (16) $ 9 $ 75 $ 52 148 Six Months Ended June 30, 2025 Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ (20) $ — $ — $ — $ — $ — $ — Generation & Marketing Revenues 60 — — — — — — Electric Generation, Transmission and Distribution Revenues — — — (21) — — — Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 4 — 4 — — — — Regulatory Assets (a) (5) — — (1) — (2) (2) Regulatory Liabilities (a) 230 — 60 15 6 67 71 Total Gain (Loss) on Risk Management Contracts $ 269 $ — $ 64 $ (7) $ 6 $ 65 $ 69 (a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same line item on the statements of income as that of the associated risk being hedged. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e., hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts net income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. 149 The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships: Carrying Amount of the Hedged Liabilities Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities June 30, 2026 December 31, 2025 June 30, 2026 December 31, 2025 (in millions) Long-term Debt (a) (b) $ (483) $ (484) $ 16 $ 15 (a)Amounts included within Long-term Debt on the balance sheet. (b)Amounts include $(11) million and $(14) million as of June 30, 2026 and December 31, 2025, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued. The pretax effects of fair value hedge accounting on income were as follows: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in millions) Gain (Loss) on Interest Rate Contracts: Fair Value Hedging Instruments (a) $ 6 $ 21 $ 3 $ 24 Fair Value Portion of Long-term Debt (a) (6) (21) (3) (24) (a)Gain (Loss) is included in Interest Expense on the statements of income. Accounting for Cash Flow Hedging Strategies (Applies to AEP, AEP Texas, APCo, I&M, PSO and SWEPCo) For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity, Fuel and Other Consumables Used for Electric Generation on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2026 and 2025, AEP applied cash flow hedging to outstanding power derivatives and the Registrant Subsidiaries did not. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2026 and 2025, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income. 150 Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on the Registrants’ Balance Sheets June 30, 2026 December 31, 2025 Portion Expected to Portion Expected to AOCI be Reclassed to AOCI be Reclassed to Gain (Loss) Net Income During Gain (Loss) Net Income During Net of Tax the Next Twelve Months Net of Tax the Next Twelve Months Commodity Interest Rate Commodity Interest Rate Commodity Interest Rate Commodity Interest Rate (in millions) AEP $ 85 $ (1) $ 50 $ — $ 78 $ (1) $ 31 $ — AEP Texas — 6 — 1 — 6 — 1 APCo — 4 — 1 — 4 — 1 I&M — (5) — — — (5) — — PSO — 2 — — — 2 — — SWEPCo — 1 — — — 1 — — As of June 30, 2026, the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is approximately 9 years. The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Credit-Risk-Related Contingent Features Credit Downgrade Triggers (Applies to AEP) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The total exposure of AEP’s derivative contracts with collateral triggering events in a net liability position was immaterial as of June 30, 2026 and December 31, 2025. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of June 30, 2026 and December 31, 2025. 151 Cross-Acceleration Triggers (Applies to AEP) Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by the Registrants under any of their outstanding debt of at least $50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. AEP had derivative contracts with cross-acceleration provisions in a net liability position of $27 million and $30 million and no cash collateral posted as of June 30, 2026 and December 31, 2025, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. The Registrant Subsidiaries had no derivative contracts with cross-acceleration provisions as of June 30, 2026 and December 31, 2025. Cross-Default Triggers (Applies to AEP, APCo, PSO and SWEPCo) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. AEP had derivative contracts with cross-default provisions in a net liability position of $179 million and $183 million and no cash collateral posted as of June 30, 2026 and December 31, 2025, respectively, after considering contractual netting arrangements. APCo, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $12 million, $28 million and $13 million, respectively, and no cash collateral posted as of June 30, 2026. APCo, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $2 million, $27 million and $10 million, respectively, and no cash collateral posted as of December 31, 2025. If a cross-default provision would have been triggered, settlement at fair value would have been required. The other Registrant Subsidiaries had immaterial derivative contracts with cross-default provisions in a net liability position as of June 30, 2026 and December 31, 2025. 152 10. FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurement” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. 153 Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: June 30, 2026 December 31, 2025 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 50,808 $ 48,075 $ 47,322 $ 44,930 AEP Texas 7,696 7,199 7,016 6,586 AEPTCo 6,756 5,923 6,599 5,812 APCo 7,435 7,290 6,259 6,147 I&M 4,146 3,836 3,561 3,288 OPCo 3,720 3,320 3,718 3,331 PSO 3,527 3,326 3,526 3,349 SWEPCo 4,858 4,461 4,974 4,603 Fair Value Measurements of Other Temporary Investments and Restricted Cash (Applies to AEP) Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments and Restricted Cash: June 30, 2026 Gross Gross Unrealized Unrealized Fair Other Temporary Investments and Restricted Cash Cost Gains Losses Value (in millions) Restricted Cash (a) $ 72 $ — $ — $ 72 Other Cash Deposits 10 — — 10 Fixed Income Securities – Mutual Funds (b) 176 — (3) 173 Equity Securities – Mutual Funds 13 32 — 45 Total Other Temporary Investments and Restricted Cash $ 271 $ 32 $ (3) $ 300 December 31, 2025 Gross Gross Unrealized Unrealized Fair Other Temporary Investments and Restricted Cash Cost Gains Losses Value (in millions) Restricted Cash (a) $ 71 $ — $ — $ 71 Other Cash Deposits 13 — — 13 Fixed Income Securities – Mutual Funds (b) 167 — (2) 165 Equity Securities – Mutual Funds 13 29 — 42 Total Other Temporary Investments and Restricted Cash $ 264 $ 29 $ (2) $ 291 (a)Primarily represents amounts held for the repayment of debt. (b)Primarily short and intermediate maturities which may be sold and do not contain maturity dates. 154 The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in millions) Proceeds from Investment Sales $ — $ 7 $ 7 $ 17 Purchases of Investments 13 5 15 7 Gross Realized Gains on Investment Sales — — 1 4 Gross Realized Losses on Investment Sales — 1 — 1 Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: •Acceptable investments (rated investment grade or above when purchased). •Maximum percentage invested in a specific type of investment. •Prohibition of investment in obligations of AEP, I&M or their affiliates. •Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by an external investment manager that must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies debt securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments: June 30, 2026 December 31, 2025 Gross Gross Other-Than- Gross Gross Other-Than- Fair Unrealized Unrealized Temporary Fair Unrealized Unrealized Temporary Value Gains Losses Impairments Value Gains Losses Impairments (in millions) Cash and Cash Equivalents $ 22 $ — $ — $ — $ 29 $ — $ — $ — Fixed Income Securities: United States Government 1,322 8 (3) (17) 1,351 22 (1) (15) Corporate Debt 412 3 (10) (6) 376 6 (7) (6) Subtotal Fixed Income Securities 1,734 11 (13) (23) 1,727 28 (8) (21) Equity Securities - Domestic 3,485 2,928 (2) — 3,160 2,621 (1) — Spent Nuclear Fuel and Decommissioning Trusts $ 5,241 $ 2,939 $ (15) $ (23) $ 4,916 $ 2,649 $ (9) $ (21) 155 The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (in millions) Proceeds from Investment Sales $ 661 $ 717 $ 1,209 $ 1,294 Purchases of Investments 676 729 1,249 1,330 Gross Realized Gains on Investment Sales 3 2 8 4 Gross Realized Losses on Investment Sales 3 2 7 3 The base cost of fixed income securities was $1.8 billion and $1.7 billion as of June 30, 2026 and December 31, 2025, respectively. The base cost of equity securities was $560 million and $540 million as of June 30, 2026 and December 31, 2025, respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2026 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 450 After 1 year through 5 years 608 After 5 years through 10 years 297 After 10 years 379 Total $ 1,734 156 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2026 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments and Restricted Cash Restricted Cash $ 52 $ — $ — $ 20 $ 72 Other Cash Deposits (a) — — — 10 10 Fixed Income Securities – Mutual Funds 173 — — — 173 Equity Securities – Mutual Funds (b) 45 — — — 45 Total Other Temporary Investments and Restricted Cash 270 — — 30 300 Risk Management Assets Risk Management Commodity Contracts (c) (d) 5 1,297 537 (1,186) 653 Cash Flow Hedges: Commodity Hedges (c) — 117 18 (20) 115 Total Risk Management Assets 5 1,414 555 (1,206) 768 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8 — — 14 22 Fixed Income Securities: United States Government — 1,322 — — 1,322 Corporate Debt — 412 — — 412 Subtotal Fixed Income Securities — 1,734 — — 1,734 Equity Securities – Domestic (b) 3,485 — — — 3,485 Total Spent Nuclear Fuel and Decommissioning Trusts 3,493 1,734 — 14 5,241 Total Assets $ 3,768 $ 3,148 $ 555 $ (1,162) $ 6,309 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 4 $ 1,201 $ 174 $ (1,087) $ 292 Cash Flow Hedges: Commodity Hedges (c) — 28 1 (21) 8 Fair Value Hedges — 27 — — 27 Total Risk Management Liabilities $ 4 $ 1,256 $ 175 $ (1,108) $ 327 157 Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2025 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Other Temporary Investments and Restricted Cash Restricted Cash $ 48 $ — $ — $ 23 $ 71 Other Cash Deposits (a) — — — 13 13 Fixed Income Securities – Mutual Funds 165 — — — 165 Equity Securities – Mutual Funds (b) 42 — — — 42 Total Other Temporary Investments and Restricted Cash 255 — — 36 291 Risk Management Assets Risk Management Commodity Contracts (c) (f) 2 831 393 (713) 513 Cash Flow Hedges: Commodity Hedges (c) — 100 18 (14) 104 Total Risk Management Assets 2 931 411 (727) 617 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14 — — 15 29 Fixed Income Securities: United States Government — 1,351 — — 1,351 Corporate Debt — 376 — — 376 Subtotal Fixed Income Securities — 1,727 — — 1,727 Equity Securities – Domestic (b) 3,160 — — — 3,160 Total Spent Nuclear Fuel and Decommissioning Trusts 3,174 1,727 — 15 4,916 Total Assets $ 3,431 $ 2,658 $ 411 $ (676) $ 5,824 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 4 $ 752 $ 151 $ (633) $ 274 Cash Flow Hedges: Commodity Hedges (c) — 19 1 (14) 6 Fair Value Hedges — 30 — — 30 Total Risk Management Liabilities $ 4 $ 801 $ 152 $ (647) $ 310 158 AEP Texas Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2026 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 13 $ — $ — $ — $ 13 Risk Management Assets Risk Management Commodity Contracts (c) — 1 — (1) — Total Assets $ 13 $ 1 $ — $ (1) $ 13 December 31, 2025 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 14 $ — $ — $ — $ 14 159 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2026 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 25 $ — $ — $ — $ 25 Risk Management Assets Risk Management Commodity Contracts (c) — 2 173 (4) 171 Total Assets $ 25 $ 2 $ 173 $ (4) $ 196 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ 14 $ 2 $ (4) $ 12 December 31, 2025 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 18 $ — $ — $ — $ 18 Risk Management Assets Risk Management Commodity Contracts (c) — 3 81 (2) 82 Total Assets $ 18 $ 3 $ 81 $ (2) $ 100 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ 6 $ — $ (3) $ 3 160 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2026 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) $ — $ 26 $ 26 $ (30) $ 22 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8 — — 14 22 Fixed Income Securities: United States Government — 1,322 — — 1,322 Corporate Debt — 412 — — 412 Subtotal Fixed Income Securities — 1,734 — — 1,734 Equity Securities - Domestic (b) 3,485 — — — 3,485 Total Spent Nuclear Fuel and Decommissioning Trusts 3,493 1,734 — 14 5,241 Total Assets $ 3,493 $ 1,760 $ 26 $ (16) $ 5,263 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ 31 $ 4 $ (35) $ — December 31, 2025 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) $ — $ 12 $ 9 $ (11) $ 10 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14 — — 15 29 Fixed Income Securities: United States Government — 1,351 — — 1,351 Corporate Debt — 376 — — 376 Subtotal Fixed Income Securities — 1,727 — — 1,727 Equity Securities - Domestic (b) 3,160 — — — 3,160 Total Spent Nuclear Fuel and Decommissioning Trusts 3,174 1,727 — 15 4,916 Total Assets $ 3,174 $ 1,739 $ 9 $ 4 $ 4,926 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ 11 $ — $ (11) $ — 161 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2026 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) $ — $ 1 $ — $ (1) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ — $ 28 $ — $ 28 December 31, 2025 Level 1 Level 2 Level 3 Other Total Liabilities: (in millions) Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ — $ 33 $ — $ 33 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2026 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) $ — $ 1 $ 43 $ (1) $ 43 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ 29 $ — $ (1) $ 28 December 31, 2025 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) $ — $ 1 $ 43 $ (2) $ 42 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ 28 $ 2 $ (2) $ 28 162 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2026 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 14 $ — $ — $ — $ 14 Risk Management Assets Risk Management Commodity Contracts (c) — 1 42 (1) 42 Total Assets $ 14 $ 1 $ 42 $ (1) $ 56 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ 13 $ — $ — $ 13 December 31, 2025 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding $ 15 $ — $ — $ — $ 15 Risk Management Assets Risk Management Commodity Contracts (c) — — 37 (2) 35 Total Assets $ 15 $ — $ 37 $ (2) $ 50 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) $ — $ 11 $ 2 $ (2) $ 11 (a)Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b)Amounts represent publicly traded equity securities and equity-based mutual funds. (c)Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d)The June 30, 2026 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(1) million in 2026 and $2 million in periods 2027-2029; Level 2 matures $20 million in 2026, $76 million in periods 2027-2029 and $1 million in periods 2030-2031; Level 3 matures $156 million in 2026, $224 million in periods 2027-2029, $(3) million in periods 2030-2031 and $(14) million in periods 2032-2035. Risk management commodity contracts are substantially comprised of power contracts. (e)Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f)The December 31, 2025 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(2) million in 2026; Level 2 matures $12 million in 2026, $65 million in periods 2027-2029, and $1 million in periods 2030-2031; Level 3 matures $210 million in 2026, $51 million in periods 2027-2029, $(6) million in periods 2030-2031 and $(13) million in periods 2032-2034. Risk management commodity contracts are substantially comprised of power contracts. 163 The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended June 30, 2026 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2026 $ 132 $ 21 $ 2 $ (32) $ 21 $ 15 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 86 50 6 — 8 9 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (7) — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) 2 — — — — — Settlements (157) (71) (8) 2 (29) (24) Transfers into Level 3 (d) (e) 1 — — — — — Transfers out of Level 3 (e) (2) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 325 171 22 2 43 42 Balance as of June 30, 2026 $ 380 $ 171 $ 22 $ (28) $ 43 $ 42 Three Months Ended June 30, 2025 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2025 $ 123 $ 8 $ 4 $ (51) $ 15 $ 13 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 53 10 3 — 18 19 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (3) — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) (1) — — — — — Settlements (101) (18) (7) 2 (33) (32) Transfers into Level 3 (d) (e) 5 — — — — — Transfers out of Level 3 (e) (2) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 309 108 12 1 97 69 Balance as of June 30, 2025 $ 383 $ 108 $ 12 $ (48) $ 97 $ 69 164 Six Months Ended June 30, 2026 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2025 $ 259 $ 81 $ 9 $ (33) $ 41 $ 35 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 265 162 12 1 47 18 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (8) — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) 10 — — — — — Settlements (473) (243) (20) 2 (88) (52) Transfers into Level 3 (d) (e) 2 — — — — — Transfers out of Level 3 (e) (1) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 326 171 21 2 43 41 Balance as of June 30, 2026 $ 380 $ 171 $ 22 $ (28) $ 43 $ 42 Six Months Ended June 30, 2025 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2024 $ 166 $ 35 $ 6 $ (47) $ 20 $ 17 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 154 49 13 — 38 42 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 17 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) 6 — — — — — Settlements (263) (84) (19) 4 (58) (59) Transfers into Level 3 (d) (e) — — — — — — Transfers out of Level 3 (e) — — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 303 108 12 (5) 97 69 Balance as of June 30, 2025 $ 383 $ 108 $ 12 $ (48) $ 97 $ 69 (a)Included in revenues on the statements of income. (b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (c)Included in cash flow hedges on the statements of comprehensive income. (d)Represents existing assets or liabilities that were previously categorized as Level 2. (e)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable. 165 The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs June 30, 2026 Significant Input/Range Type of Fair Value Valuation Unobservable Weighted Company Input Assets Liabilities Technique Input (a) Low High Average (b) (in millions) AEP Energy Contracts $ 215 $ 156 Discounted Cash Flow Forward Market Price $ 7.89 $ 875.00 $ 54.52 AEP FTRs 340 19 Discounted Cash Flow Forward Market Price (76.06) 238.16 1.56 APCo FTRs 173 2 Discounted Cash Flow Forward Market Price (2.61) 56.36 3.92 I&M FTRs 26 4 Discounted Cash Flow Forward Market Price (3.47) 42.39 1.06 OPCo Energy Contracts — 28 Discounted Cash Flow Forward Market Price 21.81 106.13 51.87 PSO FTRs 43 — Discounted Cash Flow Forward Market Price (20.83) 1.43 (7.09) SWEPCo FTRs 42 — Discounted Cash Flow Forward Market Price (20.83) 1.43 (7.09) December 31, 2025 Significant Input/Range Type of Fair Value Valuation Unobservable Weighted Company Input Assets Liabilities Technique Input (a) Low High Average (b) (in millions) AEP Energy Contracts $ 224 $ 144 Discounted Cash Flow Forward Market Price $ 5.65 $ 141.75 $ 50.61 AEP FTRs 187 8 Discounted Cash Flow Forward Market Price (32.49) 21.68 0.49 APCo FTRs 81 — Discounted Cash Flow Forward Market Price (0.26) 17.55 3.47 I&M FTRs 9 — Discounted Cash Flow Forward Market Price (0.46) 21.68 1.60 OPCo Energy Contracts — 33 Discounted Cash Flow Forward Market Price 21.44 85.92 50.10 PSO FTRs 43 2 Discounted Cash Flow Forward Market Price (32.49) 8.54 (5.49) SWEPCo FTRs 37 2 Discounted Cash Flow Forward Market Price (32.49) 8.54 (5.49) (a)Represents market prices in dollars per MWh. (b)The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term. The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of June 30, 2026 and December 31, 2025: Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) 166 11. INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The Registrants’ interim ETR reflect the estimated annual ETR for 2026 and 2025, adjusted for tax expense associated with certain discrete items. The ETR for each of the Registrants are included in the following tables: Three Months Ended June 30, 2026 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo U.S. Federal Statutory Rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % Increase (Decrease) due to: State and Local Income Taxes, Net 3.5 % 0.6 % 2.4 % (0.5) % 3.8 % 1.0 % 3.0 % (7.7) % Tax Reform Excess ADIT Reversal (3.2) % (1.5) % 0.2 % (5.4) % (2.6) % (11.3) % (6.7) % (4.1) % Production and Investment Tax Credits (13.0) % (0.1) % — % (13.8) % (13.7) % — % (156.3) % (110.8) % Reversal of Origination Flow-Through 0.8 % 0.1 % 0.2 % 2.3 % 1.5 % 0.6 % 0.3 % 1.1 % AFUDC Equity (1.6) % (1.6) % (1.9) % (1.0) % (0.8) % (1.8) % (1.4) % (2.7) % Other (1.0) % 0.2 % (0.1) % (0.6) % (0.7) % 0.4 % (5.4) % (1.6) % Effective Income Tax Rate 6.5 % 18.7 % 21.8 % 2.0 % 8.5 % 9.9 % (145.5) % (104.8) % Three Months Ended June 30, 2025 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo U.S. Federal Statutory Rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % Increase (Decrease) due to: State and Local Income Taxes, Net 0.6 % 0.9 % 2.5 % 0.8 % 1.1 % 1.0 % 3.2 % (2.8) % Tax Reform Excess ADIT Reversal (0.4) % (2.1) % 0.6 % (2.0) % 2.8 % (2.7) % (2.7) % 2.5 % Remeasurement of Excess ADIT (37.0) % — % (54.3) % (26.0) % (40.8) % — % (41.4) % (79.4) % Production and Investment Tax Credits (6.7) % (0.1) % — % (0.1) % (18.7) % — % (69.3) % (40.7) % Reversal of Origination Flow-Through — % 0.1 % 0.2 % (4.1) % 1.8 % 0.6 % 0.3 % 0.9 % AFUDC Equity (1.0) % (1.2) % (0.8) % (0.9) % (0.8) % (1.5) % (1.4) % (1.5) % Flow-Through of CAMT (0.3) % — % — % (3.4) % — % — % — % — % Other (0.4) % 0.1 % — % — % — % (0.1) % 0.2 % (0.9) % Effective Income Tax Rate (24.2) % 18.7 % (30.8) % (14.7) % (33.6) % 18.3 % (90.1) % (100.9) % 167 Six Months Ended June 30, 2026 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo U.S. Federal Statutory Rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % Increase (Decrease) due to: State and Local Income Taxes, Net 2.2 % 0.6 % 2.4 % (0.2) % 3.8 % 1.0 % 4.6 % (12.8) % Tax Reform Excess ADIT Reversal (3.2) % (1.5) % 0.2 % (4.9) % (2.5) % (11.3) % 68.6 % (6.8) % Production and Investment Tax Credits (11.7) % (0.1) % — % (5.6) % (10.1) % — % 2,286.2 % (a) (186.0) % Reversal of Origination Flow-Through 0.8 % 0.1 % 0.2 % 2.0 % 1.4 % 0.6 % (2.9) % 1.8 % AFUDC Equity (1.6) % (1.6) % (1.9) % (0.9) % (0.7) % (1.8) % 14.2 % (4.4) % Flow-Through of CAMT (1.4) % — % — % (6.8) % — % — % — % — % Other (0.6) % — % 0.1 % 0.1 % (0.4) % 0.1 % 8.3 % 1.2 % Effective Income Tax Rate 5.5 % 18.5 % 22.0 % 4.7 % 12.5 % 9.6 % 2,400.0 % (a) (186.0) % (a)The effective tax rate of PSO reflects a tax benefit. The resulting positive rate is attributable to the recognition of tax benefits in a period of pretax book losses. Six Months Ended June 30, 2025 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo U.S. Federal Statutory Rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % Increase (Decrease) due to: State and Local Income Taxes, Net 0.9 % 0.6 % 2.5 % 1.0 % 2.0 % 1.3 % 3.0 % (2.2) % Tax Reform Excess ADIT Reversal (1.4) % (2.8) % 0.4 % (2.4) % 0.2 % (3.2) % (3.1) % 0.1 % Remeasurement of Excess ADIT (19.5) % — % (34.4) % (8.1) % (24.1) % — % (23.5) % (45.7) % Production and Investment Tax Credits (6.6) % (0.1) % — % (0.1) % (15.8) % — % (51.3) % (36.6) % Reversal of Origination Flow-Through 0.2 % 0.1 % 0.2 % (1.8) % 1.8 % 0.7 % 0.2 % 0.8 % AFUDC Equity (1.1) % (1.1) % (1.1) % (0.7) % (0.7) % (1.6) % (1.0) % (1.4) % Other 0.1 % (0.1) % — % 0.1 % — % — % 0.1 % (0.2) % Effective Income Tax Rate (6.4) % 17.6 % (11.4) % 9.0 % (15.6) % 18.2 % (54.6) % (64.2) % Income Taxes Paid The following tables show the amount of income taxes paid or (received) on an interim basis, for each Registrant: Six Months Ended June 30, 2026 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Income Taxes Paid/(Received) $ 18 $ (9) $ 85 $ (46) $ 106 $ (40) $ (31) $ (28) Transfer Credits (64) — — (4) (50) — (6) (3) Total Cash Paid/(Received) $ (46) $ (9) $ 85 $ (50) $ 56 $ (40) $ (37) $ (31) Six Months Ended June 30, 2025 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Income Taxes Paid/(Received) $ 59 $ (8) $ (21) $ (19) $ 3 $ 1 $ (4) $ (28) Transfer Credits (17) — — — — — (9) (9) Total Cash Paid/(Received) $ 42 $ (8) $ (21) $ (19) $ 3 $ 1 $ (13) $ (37) 168 Federal and State Income Tax Audit Status The statute of limitations (SOL) for the IRS to examine AEP and subsidiaries’ originally filed federal income tax returns has expired for tax years prior to 2022. In July 2026, AEP received notification that its 2023 federal income tax return would no longer be audited and only remains open for potential items identified in subsequent year exams. In the second quarter of 2026, AEP received notification that its 2024 federal income tax return was selected for IRS examination. That examination began in July 2026. AEP and subsidiaries file income tax returns in various state and local jurisdictions. AEP and subsidiaries are not currently under any state and local income tax examinations. Generally, the SOL have expired for tax years prior to 2022. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity. Federal Legislation On July 4, 2025, President Trump signed H.R. 1 into law, commonly known as the One Big Beautiful Bill Act (OBBBA). This budget reconciliation legislation modifies and accelerates the phase out of technology neutral PTCs and ITCs available for wind and solar projects, adds new restrictions to guard against certain foreign ownership, influence or assistance with respect to otherwise credit-eligible projects and makes 100% bonus depreciation permanent for certain non-regulated entities. With the exception of bonus depreciation, this legislation is not expected to have a material impact on the Registrants. On August 15, 2025, the Department of Treasury and the IRS issued new and revised wind and solar tax credit guidance, Notice 2025-42, which modified the definition of “begin construction” for tax purposes by eliminating the previously available 5% cost safe harbor standard for projects that begin construction after September 1, 2025. Notice 2025-42 was vacated in Oregon Environmental Council v. IRS, No. CV-25-4400 (D.D.C. June 6, 2026), which restored the availability of the 5% safe harbor. There is, however, uncertainty as to whether a court would overturn the ruling on appeal. Neither the ruling nor any related subsequent decision is expected to have a material impact on the Registrants. On February 18, 2026, the Department of Treasury and the IRS issued additional interim guidance on the application of CAMT, Notice 2026-7. This guidance allows taxpayers to deduct certain tax-deductible repairs when determining adjusted financial statement income for CAMT purposes. This guidance is expected to result in a reduction to applicable Registrants’ prior and future CAMT liabilities. Additional significant guidance from the Department of Treasury and the IRS is expected on the tax provisions in recently enacted legislation. AEP will continue to monitor any issued guidance and evaluate the impact on AEP’s future net income, cash flows and financial condition. 169 12. FINANCING ACTIVITIES The disclosures in this note apply to all Registrants, unless indicated otherwise. Common Stock (Applies to AEP) ATM Program In November 2025, AEP filed a prospectus supplement under which it may sell up to $3.5 billion of its common stock through an ATM program. In first quarter 2026, 2 million shares of common stock were issued for $264 million in net proceeds. In addition to these issuances and sales of shares of common stock, AEP also may use the ATM program to enter into forward sale agreements. See below for information regarding shares issued or expected to be issued under forward sale agreements. Forward Equity Agreements AEP has entered into the following forward sales under its ATM program and its March 2025 and May 2026 forward sale of equity agreements as follows: Final Maturity Common Shares into Forward (Number of Shares) Settled (Number of Shares) (a) Settled (a) Common Shares Remaining in Forward (Number of Shares) Expected Proceeds (b) (in millions) March 2025 Forward Sale December 2026 23 5 $ 500 18 $ 1,728 ATM Forward December 2026 3 — — 3 374 May 2026 Forward Sale May 2028 24 — — 24 2,932 (a)The 5 million shares were settled in fiscal year end 2025. (b)Actual cash proceeds will be impacted by the timing of settlement. Forward prices are based on the public offering price (net of underwriting fees), increased for the overnight bank funding rate, less a spread and less expected dividends on AEP’s common stock during the period the agreements are outstanding. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding, net of issuance costs and premiums or discounts: Type of Debt June 30, 2026 December 31, 2025 (in millions) Senior Unsecured Notes $ 40,068 $ 37,190 Pollution Control Bonds 1,636 1,637 Notes Payable 605 683 Securitization Bonds 2,305 984 Spent Nuclear Fuel Obligation (a) 336 330 Junior Subordinated Notes 4,682 4,681 Other Long-term Debt 1,176 1,817 Total Long-term Debt Outstanding 50,808 47,322 Long-term Debt Due Within One Year 2,821 3,194 Long-term Debt $ 47,987 $ 44,128 (a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $389 million and $381 million as of June 30, 2026 and December 31, 2025, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. 170 Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first six months of 2026 are shown in the following tables: Principal Interest Company Type of Debt Amount (a) Rate Due Date Issuances: (in millions) (%) AEP Pollution Control Bonds $ 50 3.50 2030 AEP Texas Senior Unsecured Notes 750 5.20 2036 AEPTCo Other Long-term Debt 124 Variable 2028 AEPTCo Senior Unsecured Notes 650 5.25 2036 APCo Securitization Bonds 450 4.96 2035 APCo Securitization Bonds 326 5.37 2040 APCo Securitization Bonds 600 5.84 2046 I&M Senior Unsecured Notes 650 5.60 2056 SWEPCo Senior Unsecured Notes 300 5.30 2033 SWEPCo Senior Unsecured Notes 600 5.20 2036 SWEPCo Senior Unsecured Notes 500 5.90 2056 Non-Registrant: KPCo Pollution Control Bonds 65 3.75 2030 Transource Energy Other Long-term Debt 23 Variable 2028 Total Issuances $ 5,088 (a)Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. 171 Principal Interest Company Type of Debt Amount Paid (a) Rate Due Date Retirements and Principal Payments: (in millions) (%) AEP Pollution Control Bonds $ 50 3.20 2026 AEP Texas Securitization Bonds 12 2.29 2029 AEP Texas Senior Unsecured Notes 50 3.81 2026 AEPTCo Other Long-term Debt 613 Variable 2028 APCo Other Long-term Debt 175 Variable 2026 APCo Other Long-term Debt 1 13.72 2026 APCo Securitization Bonds 15 3.77 2028 I&M Notes Payable 2 3.44 2026 I&M Notes Payable 3 5.93 2027 I&M Notes Payable 10 6.01 2028 I&M Notes Payable 9 6.41 2028 I&M Notes Payable 19 4.89 2029 I&M Notes Payable 20 Variable 2030 SWEPCo Securitization Bonds 8 4.88 2039 SWEPCo Senior Unsecured Notes 500 1.65 2026 Non-Registrant: KPCo Pollution Control Bonds 65 4.70 2026 KPCo Securitization Bonds 9 5.30 2045 Transource Energy Senior Unsecured Notes 2 2.75 2050 WPCo Notes Payable 15 6.89 2034 Total Retirements and Principal Payments $ 1,578 (a)In March 2026, SWEPCo retired $1 billion of 4.24% Affiliated Notes Payable due in 2028. Financing Activities Subsequent Events In July 2026, AEP made a capital contribution of $37 million to SWEPCo. In July 2026, AEPTCo issued $75 million of variable rate Other Long-term Debt due in 2028. In July 2026, I&M retired $10 million of Notes Payable related to DCC Fuel. In July 2026, Transource Energy issued $9 million of variable rate Other Long-term Debt due in 2028. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. AEPTCo’s contractually-defined priority debt was 0.3% of consolidated tangible net assets as of June 30, 2026. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreements. Dividend Restrictions Subsidiary Restrictions Parent depends on its subsidiaries to pay dividends to shareholders. AEP subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. 172 All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act requirement that prohibits the payment of dividends out of capital accounts in certain circumstances; payment of dividends is generally allowed out of retained earnings. The Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to APCo and I&M. Certain AEP subsidiaries have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. The Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. Corporate Borrowing Program (Applies to all Registrant Subsidiaries) AEP subsidiaries use a corporate borrowing program to meet their short-term borrowing needs. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP. The AEP Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of June 30, 2026 and December 31, 2025 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits for the six months ended June 30, 2026 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2026 Limit (in millions) AEP Texas $ 624 $ 186 $ 308 $ 98 $ (354) $ 750 AEPTCo 205 342 46 72 10 820 (a) APCo 594 648 199 24 (109) 950 I&M 146 855 37 159 63 750 OPCo 198 42 95 17 (64) 750 PSO 505 — 348 — (394) 950 SWEPCo 375 1,308 257 85 (311) 950 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. 173 The activity in the above table does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC participates in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of June 30, 2026 and December 31, 2025 are included in Advances to Affiliates on AEP Texas’ balance sheets. The Nonutility Money Pool participants’ activity for the six months ended June 30, 2026 is described in the following table: Maximum Loans Average Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Company Money Pool Money Pool June 30, 2026 (in millions) AEP Texas $ 7 $ 7 $ 7 AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of June 30, 2026 and December 31, 2025 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct financing activities with AEP and corresponding authorized borrowing limit for the six months ended June 30, 2026 are described in the following table: Borrowings Authorized Maximum Maximum Average Average from AEP Loans to Short-term Borrowings Loans Borrowings Loans as of AEP as of Borrowing Company from AEP to AEP from AEP to AEP June 30, June 30, Limit (a) (in millions) AEPTCo Parent $ — $ 578 $ — $ 144 $ — $ 156 $ — SWTCo 2 — 2 — 2 — 50 (a) Amount represents the authorized short-term borrowing limit from FERC or state regulatory agencies not otherwise included in the utility money pool above. The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table: Six Months Ended June 30, 2026 2025 Maximum Interest Rate 4.13 % 4.83 % Minimum Interest Rate 3.53 % 4.14 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized in the following table: Average Interest Rate for Funds Average Interest Rate for Funds Borrowed from the Utility Money Pool Loaned to the Utility Money Pool for Six Months Ended June 30, for Six Months Ended June 30, Company 2026 2025 2026 2025 AEP Texas 3.93 % 4.69 % 4.06 % 4.72 % AEPTCo 3.95 % 4.68 % 4.01 % 4.62 % APCo 4.00 % 4.69 % 4.01 % 4.58 % I&M 3.93 % 4.69 % 3.93 % 4.64 % OPCo 4.03 % 4.65 % 3.80 % 4.70 % PSO 4.01 % 4.67 % — % 4.68 % SWEPCo 4.06 % 4.69 % 3.76 % 4.65 % 174 Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table: Six Months Ended June 30, 2026 Six Months Ended June 30, 2025 Maximum Minimum Average Maximum Minimum Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Loaned to Loaned to Loaned to Loaned to Loaned to Loaned to the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility Company Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool AEP Texas 4.13 % 3.83 % 3.99 % 4.76 % 4.64 % 4.70 % SWEPCo — % — % — % 4.76 % 4.64 % 4.70 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Six Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned June 30, from AEP from AEP to AEP to AEP from AEP to AEP 2026 4.13 % 3.83 % 4.13 % 3.83 % 3.99 % 3.99 % 2025 4.76 % 4.63 % 4.76 % 4.63 % 4.69 % 4.69 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: June 30, 2026 December 31, 2025 Outstanding Interest Outstanding Interest Company Type of Debt Amount Rate (a) Amount Rate (a) (dollars in millions) AEP Securitized Debt for Receivables (b) $ 900 3.95 % $ 900 4.00 % AEP Commercial Paper 1,125 4.07 % 605 3.92 % SWEPCo Notes Payable 3 6.00 % 3 6.30 % Total Short-term Debt $ 2,028 $ 1,508 (a)Weighted-average rate of all borrowings outstanding as of June 30, 2026 and December 31, 2025, respectively. (b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5. Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $900 million from bank conduits to purchase receivables and expires in September 2027. As of June 30, 2026, the affiliated utility subsidiaries were in compliance with all requirements under the agreement. 175 Accounts receivable information for AEP Credit was as follows: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 3.94 % 4.53 % 3.93 % 4.57 % Net Uncollectible Accounts Receivable Written-Off $ 8 $ 6 $ 16 $ 14 June 30, 2026 December 31, 2025 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 1,352 $ 1,230 Short-term – Securitized Debt of Receivables 900 900 Delinquent Securitized Accounts Receivable 71 66 Bad Debt Reserves Related to Securitization 44 42 Unbilled Receivables Related to Securitization 405 368 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were: Company June 30, 2026 December 31, 2025 (in millions) APCo $ 193 $ 203 I&M 179 175 OPCo 553 501 PSO 182 140 SWEPCo 197 169 The fees paid to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2026 2025 2026 2025 (in millions) APCo $ 3 $ 3 $ 7 $ 7 I&M 4 3 8 7 OPCo 7 8 15 15 PSO 3 3 6 6 SWEPCo 3 4 7 8 176 The proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2026 2025 2026 2025 (in millions) APCo $ 416 $ 430 $ 959 $ 1,035 I&M 648 545 1,345 1,130 OPCo 817 736 1,729 1,596 PSO 501 432 913 807 SWEPCo 474 456 895 884 177 13. VARIABLE INTEREST ENTITIES AND EQUITY METHOD INVESTMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently. AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. AEP has not provided material financial or other support that was not previously contractually required to any of its consolidated VIEs. AEP’s interests in non-consolidated VIEs are accounted for under the equity method of accounting. Consolidated Variable Interest Entities Appalachian Recovery Funding (Applies to AEP and APCo) In May 2026, Appalachian Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds primarily related to certain Virginia jurisdictional Property, Plant and Equipment balances for the Amos and Mountaineer Plants and certain Virginia jurisdictional major storm costs deferred to Regulatory Assets. Management concluded that APCo holds a variable interest in Appalachian Recovery Funding and is the primary beneficiary of the VIE because APCo has the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and has the obligation to absorb losses of, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. Therefore, APCo is required to consolidate Appalachian Recovery Funding. As of June 30, 2026, $35 million of the securitized bonds was included in Long-term Debt Due Within One Year - Nonaffiliated and $1.3 billion was included in Long-term Debt - Nonaffiliated on the balance sheets. Appalachian Recovery Funding’s securitized asset was $1.4 billion as of June 30, 2026 which is presented in Securitized Assets on the face of the balance sheets. The securitized asset represents the right to impose and collect Virginia jurisdictional recovery charges from APCo’s Virginia jurisdictional customers. The securitization bonds are payable only from and secured by the securitized asset. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Recovery Funding’s securitized asset and remits all related amounts collected from customers to Appalachian Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Recovery Funding’s assets and liabilities on APCo’s balance sheets. The 2025 Annual Report includes a detailed discussion of AEP’s and Registrant Subsidiaries’ other consolidated VIEs. 178 The balances below represent the assets and liabilities of consolidated VIEs. These balances include intercompany transactions that are eliminated upon consolidation. June 30, 2026 Consolidated VIEs SWEPCo Sabine I&M DCC Fuel AEP Texas Restoration Funding APCo Appalachian Consumer Rate Relief Funding APCo Appalachian Recovery Funding SWEPCo Storm Recovery Funding KPCo Cost Recovery Funding AEP Credit Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 1 $ 91 $ 19 $ 19 $ 21 $ 16 $ 20 $ 1,353 $ 240 $ 50 Net Property, Plant and Equipment — 163 — — — — — — — 691 Other Noncurrent Assets 72 82 87 (a) 64 (b) 1,361 309 455 (c) 12 — 7 Total Assets $ 73 $ 336 $ 106 $ 83 $ 1,382 $ 325 $ 475 $ 1,365 $ 240 $ 748 LIABILITIES AND EQUITY Current Liabilities $ 14 $ 91 $ 32 $ 31 $ 42 $ 23 $ 23 $ 1,293 $ 53 $ 45 Noncurrent Liabilities 59 245 73 50 1,333 300 450 — 136 321 Equity — — 1 2 7 2 2 72 51 382 Total Liabilities and Equity $ 73 $ 336 $ 106 $ 83 $ 1,382 $ 325 $ 475 $ 1,365 $ 240 $ 748 (a)Includes an intercompany item eliminated in consolidation of $4 million. (b)Includes an intercompany item eliminated in consolidation of $1 million. (c)Includes an intercompany item eliminated in consolidation of $16 million. December 31, 2025 Consolidated VIEs SWEPCo Sabine I&M DCC Fuel AEP Texas Restoration Funding APCo Appalachian Consumer Rate Relief Funding SWEPCo Storm Recovery Funding KPCo Cost Recovery Funding AEP Credit Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 1 $ 118 $ 18 $ 18 $ 17 $ 24 $ 1,232 $ 223 $ 45 Net Property, Plant and Equipment — 227 — — — — — — 658 Other Noncurrent Assets 80 118 98 (a) 79 (b) 312 462 (c) 10 — 4 Total Assets $ 81 $ 463 $ 116 $ 97 $ 329 $ 486 $ 1,242 $ 223 $ 707 LIABILITIES AND EQUITY Current Liabilities $ 15 $ 118 $ 31 $ 31 $ 23 $ 30 $ 1,176 $ 56 $ 50 Noncurrent Liabilities 66 345 84 64 304 454 1 102 298 Equity — — 1 2 2 2 65 65 359 Total Liabilities and Equity $ 81 $ 463 $ 116 $ 97 $ 329 $ 486 $ 1,242 $ 223 $ 707 (a)Includes an intercompany item eliminated in consolidation of $4 million. (b)Includes an intercompany item eliminated in consolidation of $1 million. (c)Includes an intercompany item eliminated in consolidation of $16 million. 179 Non-Consolidated Significant Variable Interests OVEC (Applies to AEP and OPCo) In November 2025 and December 2025, OPCo filed applications with the PUCO and FERC, respectively, to transfer its 4.3% ownership in OVEC to Parent and its 19.93% OVEC power participation entitlement to AGR. In December 2025 and April 2026, the PUCO approved the application and the FERC authorized the transaction, respectively. The transaction was completed in June 2026. As a result of the transaction, Parent remains responsible for the financial and other obligations of AGR under the intercompany power agreement. The 2025 Annual Report includes a detailed discussion of AEP’s and Registrant Subsidiaries’ other significant variable interests in non-consolidated VIEs. Equity Method Investment in Unconsolidated Entities Gigawatt AI (Applies to AEP) In August 2025, AEP and Gigawatt AI, Inc. (GWAI), a privately held company, entered into a new commercial arrangement. GWAI is focused on developing AI-centric operating systems and applications that optimize utility operations and infrastructure. AEP initially invested $100 million for a 10% ownership interest in the common stock and received a warrant for the option to acquire an additional 5% of GWAI’s common stock for $50 million. In January and April 2026, AEP made two additional $25 million investments, each for an incremental 2.5% interest in GWAI’s common stock because of GWAI’s achievement of performance-based milestones. As a result, as of June 30, 2026, AEP holds 15% of GWAI’s common stock with a cumulative investment of $150 million. In July 2026, AEP confirmed GWAI’s achievement of two additional performance-based milestones. Pursuant to the agreements, the parties are progressing with the established procedural requirements for closing the investment, which is expected in the third quarter of 2026. In connection with AEP’s equity interest, AEP was granted the right to designate one of the three members of GWAI’s board of directors. The board position is currently held by an officer of AEP and, therefore, the investment is a related-party transaction. AEP’s board participation provides AEP with direct influence over GWAI’s governance and oversight, while GWAI’s founders retain all other equity interests and board representation. AEP also acquired a perpetual software license for software developed by GWAI. The equity interest is accounted for as an equity method investment due to AEP’s ability to exercise significant influence over certain GWAI policies. As of June 30, 2026, AEP’s carrying value of the investment in GWAI was $150 million, which is recognized in Deferred Charges and Other Noncurrent Assets on the balance sheet. AEP’s proportionate share of GWAI’s losses was immaterial for the three and six months ended June 30, 2026. The common stock warrant meets the definition of a derivative instrument and is therefore required to be carried at fair value on a recurring basis. The fair value of the common stock warrant and AEP’s acquired perpetual software license were immaterial as of June 30, 2026. The 2025 Annual Report includes a detailed discussion of AEP’s and Registrant Subsidiaries’ other equity method investments. 180 14. PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to AEP and PSO. Asset Retirement Obligations The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal mining facilities. AEP records ARO for the decommissioning of the Cook Plant. The table below summarizes significant changes to the Registrants’ ARO recorded in 2026 and should be read in conjunction with the Property, Plant and Equipment note within the 2025 Annual Report. Company ARO as of December 31, 2025 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates (a) ARO as of June 30, 2026 (in millions) AEP (b)(c)(d)(e)(f) $ 3,712 $ 87 $ 3 $ (43) $ 42 $ 3,801 PSO (b)(e)(f) 143 4 — (3) 19 163 (a)Unless discussed above, primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs. (b)Includes ARO related to ash disposal facilities. (c)Includes ARO related to nuclear decommissioning costs for the Cook Plant. (d)Includes ARO related to Sabine and DHLC. (e)Includes ARO related to asbestos removal. (f)Includes ARO related to renewables. 181 15. REVENUE FROM CONTRACTS WITH CUSTOMERS The disclosures in this note apply to all Registrants, unless indicated otherwise. Disaggregated Revenues from Contracts with Customers The tables below represent AEP’s reportable segment and Registrant Subsidiary revenues from contracts with customers, net of respective provisions for refund, by type of revenue: Three Months Ended June 30, 2026 VIU (a) T&D AEPTHCo G&M Corporate and Other Reconciling Adjustments AEP Consolidated (in millions) Retail Revenues: Residential Revenues $ 1,072 $ 662 $ — $ — $ — $ — $ 1,734 Commercial Revenues 852 473 — — — — 1,325 Industrial Revenues (b) 702 145 — — — — 847 Other Retail Revenues 60 14 — — — — 74 Total Retail Revenues 2,686 1,294 — — — — 3,980 Wholesale and Competitive Retail Revenues: Generation Revenues 236 — — 47 — — 283 Transmission Revenues (c) 153 223 599 — — (538) 437 Retail, Trading and Marketing Revenues (d) — — — 603 — (16) 587 Total Wholesale and Competitive Retail Revenues 389 223 599 650 — (554) 1,307 Other Revenues from Contracts with Customers (e) 77 53 18 48 28 (50) 174 Total Revenues from Contracts with Customers 3,152 1,570 617 698 28 (604) 5,461 Other Revenues: Alternative Revenue Programs (f) (10) 9 (7) — — — (8) Other Revenues (b) (g) (22) 4 — 11 2 (3) (8) Total Other Revenues (32) 13 (7) 11 2 (3) (16) Total Revenues $ 3,120 $ 1,583 $ 610 $ 709 $ 30 $ (607) $ 5,445 (a)Beginning in the first quarter of 2026, PSO and SWEPCo incorporated fuel‑related amounts into unbilled revenues to reflect consideration earned but not yet invoiced as of the balance sheet date. The impact of this change did not have a material impact on the financial statements or related disclosures. (b)Amounts include immaterial affiliated and nonaffiliated revenues. (c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $475 million. The affiliated revenues for Vertically Integrated Utilities were $63 million. The remaining affiliated amounts were immaterial. (d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $16 million. The remaining affiliated amounts were immaterial. (e)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $27 million. The remaining affiliated amounts were immaterial. (f)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include immaterial affiliated and nonaffiliated revenues. (g)Generation & Marketing includes economic hedge activity. 182 Three Months Ended June 30, 2025 VIU T&D AEPTHCo G&M Corporate and Other Reconciling Adjustments AEP Consolidated (in millions) Retail Revenues: Residential Revenues $ 1,030 $ 612 $ — $ — $ — $ — $ 1,642 Commercial Revenues 750 420 — — — — 1,170 Industrial Revenues (a) 704 145 — — — — 849 Other Retail Revenues 61 15 — — — — 76 Total Retail Revenues 2,545 1,192 — — — — 3,737 Wholesale and Competitive Retail Revenues: Generation Revenues 237 — — 38 — — 275 Transmission Revenues (b) 157 197 699 — — (622) 431 Retail, Trading and Marketing Revenues (c) — — — 538 — (16) 522 Total Wholesale and Competitive Retail Revenues 394 197 699 576 — (638) 1,228 Other Revenues from Contracts with Customers (d) 49 46 9 3 27 (44) 90 Total Revenues from Contracts with Customers 2,988 1,435 708 579 27 (682) 5,055 Other Revenues: Alternative Revenue Programs (e) 15 12 49 — — (47) 29 Other Revenues (a) (f) 12 2 — (13) 3 (1) 3 Total Other Revenues 27 14 49 (13) 3 (48) 32 Total Revenues $ 3,015 $ 1,449 $ 757 $ 566 $ 30 $ (730) $ 5,087 (a)Amounts include immaterial affiliated and nonaffiliated revenues. (b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $558 million. The affiliated revenues for Vertically Integrated Utilities were $65 million. The remaining affiliated amounts were immaterial. (c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $16 million. The remaining affiliated amounts were immaterial. (d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $26 million. The remaining affiliated amounts were immaterial. (e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include immaterial affiliated and nonaffiliated revenues. (f)Generation & Marketing includes economic hedge activity. 183 Three Months Ended June 30, 2026 AEP Texas AEPTCo APCo I&M OPCo PSO (a) SWEPCo (a) (in millions) Retail Revenues: Residential Revenues $ 190 $ — $ 348 $ 191 $ 472 $ 224 $ 208 Commercial Revenues 119 — 183 275 354 148 166 Industrial Revenues (b) 42 — 197 159 103 97 105 Other Retail Revenues 10 — 27 2 4 30 1 Total Retail Revenues 361 — 755 627 933 499 480 Wholesale Revenues: Generation Revenues (c) — — 83 147 — 4 42 Transmission Revenues (d) 195 580 59 11 27 14 55 Total Wholesale Revenues 195 580 142 158 27 18 97 Other Revenues from Contracts with Customers (e) 17 17 16 46 35 6 16 Total Revenues from Contracts with Customers 573 597 913 831 995 523 593 Other Revenues: Alternative Revenue Programs (f) (2) (9) 2 (6) 11 (2) (5) Other Revenues (b) — — 1 (25) 6 — — Total Other Revenues (2) (9) 3 (31) 17 (2) (5) Total Revenues $ 571 $ 588 $ 916 $ 800 $ 1,012 $ 521 $ 588 (a)Beginning in the first quarter of 2026, PSO and SWEPCo incorporated fuel‑related amounts into unbilled revenues to reflect consideration earned but not yet invoiced as of the balance sheet date. The impact of this change did not have a material impact on the financial statements or related disclosures. (b)Amounts include immaterial affiliated and nonaffiliated revenues. (c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $42 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $471 million, $32 million and $22 million, respectively. The remaining affiliated amounts were immaterial. (e)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $17 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (f)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include immaterial affiliated and nonaffiliated revenues. 184 Three Months Ended June 30, 2025 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 180 $ — $ 366 $ 190 $ 432 $ 191 $ 191 Commercial Revenues 115 — 193 192 307 135 155 Industrial Revenues (a) 41 — 211 156 103 92 103 Other Retail Revenues 10 — 28 2 3 26 2 Total Retail Revenues 346 — 798 540 845 444 451 Wholesale Revenues: Generation Revenues (b) — — 77 138 — 1 48 Transmission Revenues (c) 176 682 46 19 22 16 55 Total Wholesale Revenues 176 682 123 157 22 17 103 Other Revenues from Contracts with Customers (d) 8 9 19 27 38 6 7 Total Revenues from Contracts with Customers 530 691 940 724 905 467 561 Other Revenues: Alternative Revenue Programs (e) 1 51 7 1 12 2 9 Other Revenues (a) — — — 12 2 — — Total Other Revenues 1 51 7 13 14 2 9 Total Revenues $ 531 $ 742 $ 947 $ 737 $ 919 $ 469 $ 570 (a)Amounts include immaterial affiliated and nonaffiliated revenues. (b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $36 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $555 million, $22 million and $21 million, respectively. The remaining affiliated amounts were immaterial. (d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $18 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include immaterial affiliated and nonaffiliated revenues. 185 Six Months Ended June 30, 2026 VIU (a) T&D AEPTHCo G&M Corporate and Other Reconciling Adjustments AEP Consolidated (in millions) Retail Revenues: Residential Revenues $ 2,436 $ 1,395 $ — $ — $ — $ — $ 3,831 Commercial Revenues 1,651 882 — — — — 2,533 Industrial Revenues (b) 1,351 273 — — — — 1,624 Other Retail Revenues 119 29 — — — — 148 Total Retail Revenues 5,557 2,579 — — — — 8,136 Wholesale and Competitive Retail Revenues: Generation Revenues 598 — — 99 — — 697 Transmission Revenues (c) 316 437 1,185 — — (1,057) 881 Retail, Trading and Marketing Revenues (d) — — — 1,373 — (37) 1,336 Total Wholesale and Competitive Retail Revenues 914 437 1,185 1,472 — (1,094) 2,914 Other Revenues from Contracts with Customers (e) 125 155 23 79 57 (107) 332 Total Revenues from Contracts with Customers 6,596 3,171 1,208 1,551 57 (1,201) 11,382 Other Revenues: Alternative Revenue Programs (f) (7) 7 — — — (11) (11) Other Revenues (b) (g) (29) 14 — 110 4 (5) 94 Total Other Revenues (36) 21 — 110 4 (16) 83 Total Revenues $ 6,560 $ 3,192 $ 1,208 $ 1,661 $ 61 $ (1,217) $ 11,465 (a)Beginning in the first quarter of 2026, PSO and SWEPCo incorporated fuel‑related amounts into unbilled revenues to reflect consideration earned but not yet invoiced as of the balance sheet date. The impact of this change did not have a material impact on the financial statements or related disclosures. (b)Amounts include immaterial affiliated and nonaffiliated revenues. (c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $933 million. The affiliated revenues for Vertically Integrated Utilities were $118 million. The remaining affiliated amounts were immaterial. (d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $37 million. The remaining affiliated amounts were immaterial. (e)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $56 million. The remaining affiliated amounts were immaterial. (f)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include immaterial affiliated and nonaffiliated revenues. (g)Generation & Marketing includes economic hedge activity. 186 Six Months Ended June 30, 2025 VIU T&D AEPTHCo G&M Corporate and Other Reconciling Adjustments AEP Consolidated (in millions) Retail Revenues: Residential Revenues $ 2,382 $ 1,351 $ — $ — $ — $ — $ 3,733 Commercial Revenues 1,415 802 — — — — 2,217 Industrial Revenues (a) 1,322 268 — — — — 1,590 Other Retail Revenues 115 30 — — — — 145 Total Retail Revenues 5,234 2,451 — — — — 7,685 Wholesale and Competitive Retail Revenues: Generation Revenues 542 — — 89 — — 631 Transmission Revenues (b) 278 394 1,220 — — (1,072) 820 Retail, Trading and Marketing Revenues (c) — — — 1,160 — (32) 1,128 Total Wholesale and Competitive Retail Revenues 820 394 1,220 1,249 — (1,104) 2,579 Other Revenues from Contracts with Customers (d) 101 108 18 4 70 (95) 206 Total Revenues from Contracts with Customers 6,155 2,953 1,238 1,253 70 (1,199) 10,470 Other Revenues: Alternative Revenue Programs (e) 18 16 61 — — (62) 33 Other Revenues (a) (f) (20) 7 — 60 4 (4) 47 Total Other Revenues (2) 23 61 60 4 (66) 80 Total Revenues $ 6,153 $ 2,976 $ 1,299 $ 1,313 $ 74 $ (1,265) $ 10,550 (a)Amounts include immaterial affiliated and nonaffiliated revenues. (b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $969 million. The affiliated revenues for Vertically Integrated Utilities were $104 million. The remaining affiliated amounts were immaterial. (c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $32 million. The remaining affiliated amounts were immaterial. (d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $55 million. The remaining affiliated amounts were immaterial. (e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include immaterial affiliated and nonaffiliated revenues. (f)Generation & Marketing includes economic hedge activity. 187 Six Months Ended June 30, 2026 AEP Texas AEPTCo APCo I&M OPCo PSO (a) SWEPCo (a) (in millions) Retail Revenues: Residential Revenues $ 348 $ — $ 937 $ 434 $ 1,047 $ 410 $ 406 Commercial Revenues 233 — 376 526 649 270 324 Industrial Revenues (b) 79 — 383 305 194 186 197 Other Retail Revenues 21 — 53 3 8 54 6 Total Retail Revenues 681 — 1,749 1,268 1,898 920 933 Wholesale Revenues: Generation Revenues (c) — — 177 404 — 5 94 Transmission Revenues (d) 381 1,144 120 22 55 28 113 Total Wholesale Revenues 381 1,144 297 426 55 33 207 Other Revenues from Contracts with Customers (e) 37 23 33 74 117 9 24 Total Revenues from Contracts with Customers 1,099 1,167 2,079 1,768 2,070 962 1,164 Other Revenues: Alternative Revenue Program (f) (4) (1) 3 (4) 11 (2) (5) Other Revenues (b) — — 1 (31) 16 — — Total Other Revenues (4) (1) 4 (35) 27 (2) (5) Total Revenues $ 1,095 $ 1,166 $ 2,083 $ 1,733 $ 2,097 $ 960 $ 1,159 (a)Beginning in the first quarter of 2026, PSO and SWEPCo incorporated fuel‑related amounts into unbilled revenues to reflect consideration earned but not yet invoiced as of the balance sheet date. The impact of this change did not have a material impact on the financial statements or related disclosures. (b)Amounts include immaterial affiliated and nonaffiliated revenues. (c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $97 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $925 million, $65 million and $42 million, respectively. The remaining affiliated amounts were immaterial. (e)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $34 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (f)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include immaterial affiliated and nonaffiliated revenues. 188 Six Months Ended June 30, 2025 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Retail Revenues: Residential Revenues $ 352 $ — $ 972 $ 422 $ 999 $ 366 $ 384 Commercial Revenues 234 — 388 345 569 237 296 Industrial Revenues (a) 81 — 402 290 187 162 193 Other Retail Revenues 21 — 56 3 8 46 5 Total Retail Revenues 688 — 1,818 1,060 1,763 811 878 Wholesale Revenues: Generation Revenues (b) — — 167 333 — 5 104 Transmission Revenues (c) 349 1,188 88 29 46 30 94 Total Wholesale Revenues 349 1,188 255 362 46 35 198 Other Revenues from Contracts with Customers (d) 18 18 33 57 90 15 16 Total Revenues from Contracts with Customers 1,055 1,206 2,106 1,479 1,899 861 1,092 Other Revenues: Alternative Revenue Programs (e) (1) 63 14 1 17 2 9 Other Revenues (a) — — — (20) 7 — — Total Other Revenues (1) 63 14 (19) 24 2 9 Total Revenues $ 1,054 $ 1,269 $ 2,120 $ 1,460 $ 1,923 $ 863 $ 1,101 (a)Amounts include immaterial affiliated and nonaffiliated revenues. (b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $81 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $962 million, $41 million and $31 million, respectively. The remaining affiliated amounts were immaterial. (d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $36 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial. (e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include immaterial affiliated and nonaffiliated revenues. Fixed Performance Obligations (Applies to AEP, APCo and I&M) The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of June 30, 2026. Fixed performance obligations primarily include electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrants elected to apply the exemption to not disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less. Due to the annual establishment of revenue requirements, transmission revenues are excluded from the table below. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues. Company 2026 2027-2028 2029-2030 After 2030 Total (in millions) AEP $ 44 $ 87 $ 39 $ 16 $ 186 APCo 8 32 25 12 77 I&M 2 9 5 2 18 189 Contract Assets and Liabilities Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have material contract assets as of June 30, 2026 and December 31, 2025. When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheets in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have material contract liabilities as of June 30, 2026 and December 31, 2025. Accounts Receivable from Contracts with Customers Accounts receivable from contracts with customers are presented on the Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrant Subsidiaries’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of June 30, 2026 and December 31, 2025. See “Securitized Accounts Receivables - AEP Credit” section of Note 12 for additional information. The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets: AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) June 30, 2026 $ 173 $ 137 $ 64 $ 73 $ 128 $ 92 December 31, 2025 146 113 67 74 22 65 190 16. SUBSEQUENT EVENTS In July 2026, AGR entered into a PSA to acquire a 710 MW coal-fired generation facility located in Monongalia County, West Virginia. The transaction is subject to customary closing conditions, including approval from the FERC and other required governmental approvals. The agreement was signed to support growing energy demand in the region and strengthen AEP's ability to provide reliable power at affordable prices. The Company currently expects the acquisition to close in the fourth quarter of 2026 or the first quarter of 2027, although the timing and ultimate completion of the transaction are subject to receiving the required regulatory approvals and other closing conditions. 191