AMERICAN ELECTRIC POWER CO INC

(c)Cooling degree days are calculated on a 70 degree temperature base.

•Retail Revenues increased $51 million primarily due to the following:

•A $33 million increase in revenue from rate riders.

•A $10 million increase in weather-related usage primarily due to a 25% increase in cooling degree days.

•A $9 million increase in weather-normalized revenues in all retail classes.

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

•A $12 million increase due to increased load.

•A $10 million increase in interim rates driven by increased transmission investments.

•Other Revenues increased $6 million due to the following:

•A $3 million increase primarily due to increased load.

•A $3 million increase due to an increase in pole attachment revenue.

•Other Operation and Maintenance expenses increased $49 million primarily due to the following:

•A $29 million increase due to a prior year decrease in expenses driven by legislation passed in Texas in May 2023 allowing employee financially based incentives to be recovered.

•A $20 million increase in employee-related expenses due to the voluntary severance program.

•Allowance for Equity Funds Used During Construction increased $10 million primarily due to capitalization of AFUDC on prepaid pension and OPEB.

•Interest Expense increased $3 million primarily due to the following:

•An $8 million increase due to higher debt balances and interest rates.

•Income Tax Expense increased $11 million primarilydue to the following:

•A $6 million increase due to an increase in pretax book income.

•A $6 million decrease in amortization of Excess ADIT.

The major components of the increase in revenues were as follows:

•Retail Revenues increased $80 million primarily due to the following:

•A $49 million increase in revenue from rate riders.

•A $29 million increase in weather-normalized revenues primarily in the residential and commercial classes.

•Transmission Revenues increased $31 million due to the following:

•A $20 million increase in interim rates driven by increased transmission investments.

•An $11 million increase due to increased load.

•Other Operation and Maintenance expenses increased $41 million primarily due to the following:

•A $28 million increase due to a prior year decrease in expenses driven by legislation passed in Texas in May 2023 allowing employee financially based incentives to be recovered.

•A $20 million increase in employee-related expenses due to the voluntary severance program.

•A $7 million decrease in distribution-related expenses.

•Depreciation and Amortization expenses increased $16 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes decreased $8 million primarily due to lower property taxes driven by decreased tax rates.

•Allowance for Equity Funds Used During Construction increased$13 million primarily due to the following:

•An $8 million increase primarily due to capitalization of AFUDC on prepaid pension and OPEB.

•A $5 increase due to a higher AFUDC base.

•Interest Expense increased $8 million primarily due to the following:

•A $14 million increase due to higher debt balances and interest rates.

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

•A $15 million increase due to an increase in pretax book income.

•A $6 million decrease in amortization of Excess ADIT.

ASSETS

Summary of Investment in Transmission Assets for AEPTCo

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

•Transmission Revenues increased $30 million primarily due to continued investment in transmission assets.

•Other Operation and Maintenance expenses increased $14 million primarily due to an $11 million increase in employee-related expensesdue to the voluntary severance program.

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

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

•Transmission Revenues increased $71 million primarily due to continued investment in transmission assets.

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

•An $11 million increase in employee-related expensesdue to the voluntary severance program.

•A $3 million increase in other employee-related expenses.

•Depreciation and Amortization expenses increased $21 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $6 million primarily due to higher property taxes driven by increased transmission investment.

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

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

ASSETS

LIABILITIES AND MEMBER’S EQUITY

•Retail Revenues increased $88 million primarily due to the following:

•A $50 million increase in rider revenues.

•A $24 million increase in fuel revenues.

•A $23 million increase in weather-related usage driven by a 138% increase in cooling degree days.

•Transmission Revenues decreased $5 million primarily due to transmission formula rate true-up activity.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $27 million primarily due to a decrease in under-recovered fuel deferrals in West Virginia driven by an increase in ENEC rates in September 2023.

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

•A $26 million increase in employee-related expensesdue to the voluntary severance program.

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

•A $7 million decrease due to the January 2024 completion of regulatory asset amortization related to under-earnings during the 2017-2019 Triennial Review.

•Depreciation and Amortization expenses increased $8 million primarily due to a higher depreciable base.

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

•Retail Revenues increased $178 million primarily due to the following:

•A $96 million increase in rider revenues.

•A $51 million increase in fuel revenues.

•A $40 million increase in weather-related usage driven by a 130% increase in cooling degree days and an 11% increase in heating degree days.

•Other Revenues increased $10 million primarily due to pole attachment revenue.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $84 million primarily due to a decrease in under-recovered fuel deferrals in West Virginia driven by an increase in ENEC rates in September 2023 and the amortization of Excess ADIT through the ENEC.

•Other Operation and Maintenance expenses increased $53 million primarily due to the following:

•A $35 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $26 million increase in employee-related expensesdue to the voluntary severance program.

•A $12 million decrease due to the January 2024 completion of regulatory asset amortization related to under-earnings during the 2017-2019 Triennial Review.

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

•Taxes Other Than Income Taxes increased $5 million due to an increase in Virginia state minimum taxes.

•Income Tax Expense decreased $11 million primarily due to the following:

•A $14 million decrease driven by an increase in amortization of Excess ADIT.

•A $6 million increase driven by an increase in pretax book income.

ASSETS

•Retail Revenues decreased $9 million primarily due to the following:

•A $13 million decrease in fuel revenues primarily driven by lower fuel rates in Indiana.

•A $5 million decrease in rider revenues.

•An $11 million increase in weather-related usage primarily due to a 73% increase in cooling degree days.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $8 million primarily due to decreased recoverable fuel and purchased power costs driven by decreased fuel revenues, partially offset by an increase in merchant generation at Rockport Plant.

•Purchased Electricity from AEP Affiliates increased $7 million primarily due to an increase in purchased electricity from Rockport Plant.

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

•A $7 million increase in non-utility operation expenses due to an increase in River Transportation Division (RTD) expenses and merchant operation expenses.

•A $5 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•Depreciation and Amortization expenses increased $7 million primarily due to a higher depreciable base in addition to a prior year change in the amortization period of certain assets.

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

•A $12 million reduction in the Excess ADIT regulatory liability at I&M as a result of I&M's Michigan base case treatment of stand-alone NOLCs.

•A $12 million decrease due to a decrease in pretax book income.

•Retail Revenues decreased $11 million primarily due to the following:

•A $13 million decrease due to a regulatory provision for refund.

•A $12 million decrease in weather-normalized margins primarily in the residential and industrial classes, partially offset by an increase in the commercial class.

•A $14 million increase in weather-related usage primarily due to a 73% increase in cooling degree days.

•Transmission Revenues increased $8 million primarily due to continued investment in transmission assets.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $16 million primarily due to an increase in merchant generation at Rockport Plant and a Michigan PSCR disallowance, offset by decreased recoverable fuel and purchased power costs driven by a decrease in fuel revenues.

•Purchased Electricity from AEP Affiliates increased $24 million primarily due to an increase in purchased electricity from Rockport Plant.

•Other Operation and Maintenance expenses increased $29 million primarily due to the following:

•A $16 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $7 million increase in demand side management expenses.

•A $7 million increase in non-utility operation expenses due to an increase in RTD expenses and merchant operation expenses at Rockport Plant.

•A $4 million decrease in nuclear expenses at Cook Plant primarily due to lower refueling outage expenses.

•A $3 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2024.

•A $3 million decrease in vegetation management expenses.

•Depreciation and Amortization expenses decreased $10 million primarily due to the following:

•A $17 million decrease primarily due to the deferral of Excess ADIT as a result of the PLR received regarding the treatment of stand-alone NOLCs and the timing of refunds to customers under rate rider mechanisms.

•An $8 million increase due to a higher depreciable base in addition to a prior year change in the amortization period of certain assets.

•Taxes Other Than Income Taxes increased $8 million primarily due to an increase in property taxes resulting from additional capital expenditures.

•Interest Expense decreased $6 million primarily due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.

•Income Tax Expense decreased $77 million primarily due to the following:

•A $67 million decrease due to a reduction in Excess ADIT as a result of the IRS PLR and I&M's Michigan base case treatment of stand-alone NOLCs.

•A $16 million decrease due to a decrease in pretax book income.

ASSETS

(dollars in millions)

(a)Represents energy delivered to distribution customers.

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

•Retail Revenues increased $28 million primarily due to:

•An $85 million increase in rider revenues.

•A $14 million increase in weather-related usage driven by a 129% increase in cooling degree days offset by a 38% decrease in heating degree days.

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

•A $76 million decrease due to lower customer participation in OPCo’s SSO, partially offset by higher prices.

•Off-system Sales decreased $6 million primarily due to:

•A $4 million decrease in sales at OVEC driven by lower volume.

•A $2 million decrease due to 2023 PJM settlements related to winter storm Elliott.

•Other Revenues decreased $1 million due to the following:

•A $17 million decrease in recoverable sales of renewable energy credits.

•A $13 million increase due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

•Purchased Electricity for Resale expenses decreased $83 million primarily due to the following:

•A $90 million decrease in recoverable auction purchases primarily due to lower volumes driven by lower customer participation in OPCo’s SSO.

•A $19 million decrease in recoverable alternative energy rider expenses.

•A $27 million increase in recoverable OVEC costs.

•Purchased Electricity from AEP Affiliates expenses increased $14 million primarily due to increased recoverable purchases in OPCo’s SSO auction.

•Other Operation and Maintenance expenses increased $34 million primarily due to the following:

•A $17 million increase in transmission expenses primarily due to:

•An $11 million increase in recoverable PJM expenses.

•A $7 million increase in vegetation management expenses.

•A $10 million increase in distribution expenses primarily related to recoverable storm restoration costs and recoverable vegetation management expenses.

•Asset Impairments and Other Related Charges increased $53 million primarily due to Federal EPA revised CCR rules.

•Depreciation and Amortization expenses increased $34 million primarily due to a higher depreciable base and an increase in recoverable rider depreciable assets.

•Taxes Other Than Income Taxes increased $23 million primarily due to higher property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

•Income Tax Expense decreased $14 million primarily due to a decrease in pretax book income.

•Retail Revenues increased $3 million primarily due to:

•A $174 million increase in rider revenues.

•A $30 million increase in weather-related usage driven by a 129% increase in cooling degree days.

•A $202 million decrease due to lower customer participation in OPCo’s SSO, partially offset by higher prices.

•Off-system Sales decreased $10 million primarily due to 2023 PJM settlements related to winter storm Elliott.

•Other Revenues increased $14 million due to the following:

•A $23 million increase due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

•An $11 million decrease in recoverable sales of renewable energy credits.

•Purchased Electricity for Resale expenses decreased $217 million primarily due to the following:

•A $262 million decrease in recoverable auction purchases primarily due to lower volumes driven by lower customer participation in OPCo’s SSO, partially offset by higher prices.

•A $16 million decrease in recoverable alternative energy rider expenses.

•A $62 million increase in recoverable OVEC costs.

•Purchased Electricity from AEP Affiliates expenses increased $61 million primarily due to increased recoverable purchases in OPCo’s SSO auction.

•Other Operation and Maintenance expenses increased $71 million primarily due to the following:

•A $44 million increase in transmission expenses primarily due to:

•A $37 million increase in recoverable PJM expenses.

•A $10 million increase in vegetation management expenses.

•A $26 million increase in distribution expenses primarily due to recoverable storm restoration costs and recoverable vegetation management expenses.

•Asset Impairments and Other Related Charges increased $53 million primarily due to Federal EPA revised CCR rules.

•Depreciation and Amortization expenses increased $64 million primarily due to a higher depreciable base and an increase in recoverable rider depreciable assets.

•Taxes Other Than Income Taxes increased $39 million primarily due to higher property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

•Interest Expense increased $8 million primarily due to higher debt balances and interest rates.

•Income Tax Expense decreased $14 million primarily due to a decrease in pretax book income.

ASSETS

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

•Retail Revenues decreased $22 million primarily due to the following:

•A $40 million decrease in fuel revenue primarily due to lower authorized fuel rates.

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

•A $14 million increase in base rate and rider revenues.

•A $10 million increase in weather-related usage primarily due to a 27% increase in cooling degree days.

•Other Revenues increased $6 million primarily due to associated business development revenues driven by costs associated with a third-party construction project.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $43 million primarily due to the lower current year amortization of under-recovered fuel regulatory assets driven by lower authorized fuel rates.

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

•A $10 million increase in employee-related expenses due to the voluntary severance program.

•A $9 million increase in transmission expenses primarily due to an increase in filed transmission revenue requirements.

•A $9 million increasein associated business development expenses primarily due to partially reimbursable development costs associated with a third-party construction project.

•Taxes Other Than Income Taxes increased $9 million primarily due to an increase in property taxes.

•Retail Revenues decreased $58 million primarily due to the following:

•A $97 million decrease in fuel revenue primarily due to lower authorized fuel rates.

•A $34 million increase in base rate and rider revenues.

•Other Revenues increased $13 million primarily due to associated business development revenues driven by costs associated with a third-party construction project.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $94 million primarily due to the lower current year amortization of under-recovered fuel regulatory assets driven by lower authorized fuel rates.

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

•A $13 million increase in associated business development expenses primarily due to partially reimbursable development costs associated with a third-party construction project.

•A $10 million increase in employee-related expensesdue to the voluntary severance program.

•A $9 million increase in transmission expenses primarily due to an increase in filed transmission revenue requirements.

•Depreciation and Amortization expenses increased $6 million primarily due to an increase in the amortization ofregulatory assets related to NCWF.

•Taxes Other Than Income Taxes increased $9 million primarily due to an increase in property taxes.

•Interest Expense decreased $8 million primarily due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.

•Income Tax Benefit increased $50 million primarily due to the following:

•A $44 million increase due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.

•An $8 million increase in PTCs.

CONDENSED STATEMENTS OF INCOME

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

CONDENSED STATEMENTS OF CHANGES IN

CONDENSED BALANCE SHEETS

ASSETS

CONDENSED BALANCE SHEETS

CONDENSED STATEMENTS OF CASH FLOWS

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

•Retail Revenues decreased $148 million primarily due to a $160 million probable revenue refund associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.

•Transmission Revenues increased $6 million primarily due to an increase in transmission investment.

•Other Operation and Maintenance expenses increased $40 million primarily due to the following:

•A $17 million increase in employee-related expensesdue to the voluntary severance program.

•A $10 million increase in distribution-related expenses primarily driven by storm costs in Arkansas.

•A $6 million increase due to the prior year capitalization of previously expensed renewable generation pre-construction charges.

•A $6 million increase due to a prior year decrease in expenses driven by legislation passed in Texas in May 2023 allowing employee financially based incentives to be recovered.

•Depreciation and Amortization expenses increased $15 million primarily due to an increase in amortization of regulatory assets and a higher depreciable base.

•Taxes Other Than Income Taxes decreased $7 million primarily due to a decrease in property taxes.

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

•An $8 million decrease in carrying charges on storm-related regulatory assets due to a prior year settlement agreement in Louisiana.

•A $3 million decrease due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.

•Income Tax Benefit increased $34 million primarily due to a decrease in pretax book income.

•Retail Revenues decreased $149 million primarily due to a $160 million probable revenue refund associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $21 million primarily due to a current year decrease in amortization of under-recovered fuel regulatory assets.

•Other Operation and Maintenance expenses increased $53 million primarily due to the following:

•A $17 million increase in employee-related expenses primarily due to the voluntary severance program.

•A $14 million increase due to a disallowance recorded on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.

•A $9 million increase in distribution-related expenses primarily driven by storm costs in Arkansas.

•A $5 million increase due to the prior year capitalization of previously expensed renewable generation pre-construction charges.

•A $5 million increase due to a prior year decrease in expenses driven by legislation passed in Texas in May 2023 allowing employee financially based incentives to be recovered.

•Depreciation and Amortization expenses increased $14 million primarily due to an increase in amortization of regulatory assets and a higher depreciable base, partially offset by the recognition of a regulatory asset related to NOLCs.

•Taxes Other Than Income Taxes decreased $9 million primarily due to a decrease in property taxes.

•Interest Expense decreased $22 million primarily due to the following:

•A $31 million decrease due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.

•A $7 million increase in carrying charges on storm-related regulatory assets due to a prior year settlement agreement in Louisiana.

•Income Tax Benefit increased $174 million primarily due to the following:

•A $109 million increase due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.

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

•A $32 million increase due to the reversal of a regulatory liability related to the merchant portion of Turk Plant Excess ADIT as a result of the APSC's March 2024 denial of SWEPCo's request to allow the merchant portion of the Turk Plant to serve Arkansas customers.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

ASSETS

LIABILITIES AND EQUITY

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS

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

1. SIGNIFICANT ACCOUNTING MATTERS

General

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

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and six months ended June 30, 2024 is not necessarily indicative of results that may be expected for the year ending December 31, 2024. The condensed financial statements are unaudited and should be read in conjunction with the audited 2023 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 26, 2024.

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 stock awards.

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

There were no antidilutive shares outstanding as of June 30, 2024 and 2023, respectively.

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

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:

Revision of Previously Presented Cash Flow Amounts (Applies to I&M)

In the second quarter of 2024, management identified and corrected an error in I&M’s previously issued second quarter 2023 10-Q Condensed Consolidated Statements of Cash Flows. Specifically, management did not appropriately eliminate the acquisition of nuclear fuel which remained in accounts payable as of June 30, 2023. The error resulted in an overstatement of cash flows from Operating Activities and an offsetting overstatement of cash flows used for the Acquisitions of Nuclear Fuel in the Investing Activities section of the Statements of Cash Flows. The error also resulted in an understatement of the supplemental disclosure Acquisition of Nuclear Fuel Included in Current Liabilities. Management concluded the error was not material to I&M’s previously issued second quarter 2023 financial statements. However, management determined the previously issued financial statements should be revised. The impact of the error is reflected in the table below:

2. NEW ACCOUNTING STANDARDS

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

SEC Climate Disclosure Rule

On March 6, 2024, the SEC adopted final rules that require Registrants to disclose certain climate-related information in registration statements and annual reports. The final rules require Registrants to disclose, among other things, material climate-related risks, activities to mitigate such risks and information about Registrant’s board of directors oversight and management’s role in managing material climate-related risks. The final rules also require the Registrants to provide information related to any climate-related targets or goals that are material to Registrant’s business, results of operations, or financial condition. A majority of the reporting requirements are applicable to the fiscal year beginning in 2025, with the addition of assurance reporting for GHG emissions starting in 2029 for large accelerated filers. 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. On April 4, 2024, the SEC issued an order staying the final climate disclosure rules pending the completion of judicial review at the Court of Appeals. The Registrants are currently evaluating the impact of the final rules on their respective consolidated financial statements and related disclosures.

ASU 2023-09 “Improvements to Income Tax Disclosures” (ASU 2023-09)

In December 2023, the FASB issued ASU 2023-09, to address investors’ suggested enhancements to (a) better understand an entity’s exposure to potential changes in jurisdictional tax legislation and the ensuing risks and opportunities, (b) assess income tax information that affects cash flow forecasts and capital allocation decisions and (c) identify potential opportunities to increase future cash flows.

The new standard requires an annual rate reconciliation disclosure of the following categories regardless of materiality: state and local income tax net of federal income tax effect, foreign tax effects, effect of changes in tax laws or rates enacted in the current period, effect of cross-border tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items and changes in unrecognized tax benefits.

The new standard also requires an annual disclosure of the amount of income taxes paid (net of refunds received) disaggregated by federal, state and foreign taxes and by individual jurisdictions that are equal to or greater than 5 percent of total income taxes paid. Disclosure of income (loss) from continuing operations before income tax expense (benefit) disaggregated between domestic and foreign jurisdictions and income tax expense (benefit) from continuing operations disaggregated by federal, state and foreign jurisdictions is required.

The new standard removes the requirement to disclose the cumulative amount of each type of temporary difference when a deferred tax liability is not recognized because of the exceptions to comprehensive recognition of deferred taxes related to subsidiaries and corporate joint ventures.

The amendments in the new standard may be applied on either a prospective or retrospective basis for public business entities for fiscal years beginning after December 15, 2024 with early adoption permitted. Management has not yet made a decision to early adopt the amendments to this standard or how to apply them.

ASU 2023-07 “Improvements to Reportable Segment Disclosures” (ASU 2023-07)

In November 2023, the FASB issued ASU 2023-07, to address investors’ observations that there is limited information disclosed about segment expenses and to better understand expense categories and amounts included in segment profit or loss. The new standard requires annual and interim disclosure of (a) the categories and amounts of significant segment expenses (determined by management using both qualitative and quantitative factors) that are regularly provided to the CODM and included within each reported measure of segment profit or loss, (b) the amounts and a qualitative description of “other segment items”, defined as the difference between reported segment revenues less the significant segment expenses and each reported measure of segment profit or loss disclosed, (c) reportable segment profit or loss and assets that are currently only required annually, (d) the CODM’s title and position, and an explanation of how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources and (e) a requirement that entities with a single reportable segment provide all disclosures required by ASU 2023-07 and all existing segment disclosures in Topic 280. Additionally, this new standard allows disclosure of one or more of additional profit or loss measures if the CODM uses more than one measure provided that at least one of the disclosed measures is determined in a manner “most consistent with the measurement principles under GAAP”. If multiple measures are presented, additional disclosure is required about how the CODM uses each measure to assess performance and decide how to allocate resources.

The amendments in the new standard are effective on a retrospective basis for all entities for fiscal years beginning after December 15, 2023 and interim periods within fiscal periods beginning after December 15, 2024 with early adoption permitted. Management plans to adopt ASU 2023-07 effective for the 2024 10-K.

3. COMPREHENSIVE INCOME

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

Presentation of Comprehensive Income

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

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

4. RATE MATTERS

As discussed in the 2023 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2023 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 2024 and updates the 2023 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 continuously 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 Units that have been Retired

SWEPCo

In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in 2021. See the “2020 Texas Base Rate Case” section below for additional information. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudency of the early retirement of the plant, which is being addressed in a separate proceeding. In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the prudency of the retirement of the Dolet Hills Power Station and resulted in a disallowance of $14 million in the first quarter of 2024.

In March 2023, the Pirkey Plant was retired. 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. As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. In the 2024 SWEPCo Arkansas formula rate filing, the Arkansas staff recommended that the APSC provide a return of, but not a return on, the Arkansas jurisdictional share of the Pirkey Plant. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. In July 2023, Texas ALJs issued a proposal for decision that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected the ALJs’ proposal for decision concluding the retirement of the Pirkey Plant was prudent. In the open meeting, the commissioners expressed their concerns that the analysis in support of SWEPCo’s decision to retire the Pirkey Plant was not robust enough and that SWEPCo should have re-evaluated the decision following Winter Storm Uri. The treatment of the cost of recovery of the Pirkey Plant is expected to be addressed in a future rate case. As of June 30, 2024, the Texas jurisdictional share of the net book value of the Pirkey Plant was $68 million. To the extent any portion of the Texas jurisdictional share of the net book value of the Pirkey Plant is not recoverable, it could reduce future net income and cash flows and impact financial condition.

Regulated Generating Units to be Retired

PSO

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. As ordered by the OCC, as part of the 2022 Oklahoma Base Rate Case, PSO will continue to recover Northeastern Plant, Unit 3 through 2040.

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.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of June 30, 2024, of generating facilities planned for early retirement:

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

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

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

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

(e)Represents projected retirement date of coal assets, units are being evaluated for conversion to natural gas after 2028.

(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.

Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo)

In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station. The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through rate riders. As of June 30, 2024, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $80 million, including materials and supplies, net of cost of removal collected in rates. Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses and are subject to prudency determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of June 30, 2024, SWEPCo had a net under-recovered fuel balance of $39 million, inclusive of costs related to the Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event.

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $35 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of up to $55 million, including denial of recovery of the $35 million deferral, with refunds to customers over five years. In February 2024, an ALJ issued a final recommendation which included a proposed $55 million refund to customers and the denial of recovery of the $35 million deferral. SWEPCo filed a motion to present oral arguments with the LPSC to dispute the ALJ’s recommendations. In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the fuel recovery dispute and resulted in a fuel disallowance of $11 million. The remaining $24 million regulatory asset balance will be recovered over three years with interest.

In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $48 million of Oxbow mine related costs through 2035.

If any of these costs are not recoverable or customer refunds are required, it could reduce future net income and cash flows and impact financial condition.

Pirkey Plant and Related Fuel Operations (Applies to AEP and SWEPCo)

In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or will seek recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of June 30, 2024, SWEPCo’s share of the net investment in the Pirkey Plant was $184 million, including materials and supplies, net of cost of removal. See the “Regulated Generating Units that have been Retired” section above for additional information. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of March 31, 2023, SWEPCo fuel deliveries, including billings of all fixed costs, from Sabine ceased. Additionally, as of June 30, 2024, SWEPCo had a net under-recovered fuel balance of $39 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Remaining operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses.

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. The LPSC established a procedural schedule stating staff and intervenor testimony is due in November 2024 and a hearing is scheduled for March 2025.

In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $33 million of Sabine related fuel costs through 2035.

If any of these costs are not recoverable or customer refunds are required, it could reduce future net income and cash flows and impact financial condition.

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

(a)Includes $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of June 30, 2024 and December 31, 2023, respectively. See the “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.

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

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

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

(a)Includes $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of June 30, 2024 and December 31, 2023, respectively. See the “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.

(b)Amounts include the FERC 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, 2024, AEP Texas’s cumulative revenues from interim base rate increases that are subject to a prudency review is approximately $1.2 billion. The 2024 AEP Texas base rate case described below 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.

2024 AEP Texas Base Rate Case

In February 2024, AEP Texas filed a request with the PUCT for a $164 million annual base rate increase over its adjusted test year revenues which include interim transmission and distribution rate updates. AEP Texas’s request is based upon a proposed 10.6% ROE with a capital structure of 55% debt and 45% common equity. The rate case seeks a prudence determination on all capital additions placed in service during the period January 1, 2019 through September 30, 2023. In July 2024, AEP Texas filed an unopposed settlement agreement with the PUCT. The settlement agreement includes a proposed annual revenue increase of $70 million based upon a 9.76% ROE with a capital structure of 57.5% debt and 42.5% common equity. In addition, the settlement agreement approves the prudency of capital investments placed in service for the period January 1, 2019 through September 30, 2023 and the associated $1.2 billion of interim revenues collected on those capital investments. An order is expected in the second half of 2024. If any costs in the settlement agreement 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)

ENEC (Expanded Net Energy Cost) Filings

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% 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 to initiate an appeal of this order. The West Virginia Supreme Court will hear oral arguments in September 2024 and will issue a future decision on the appeal.

In April 2024, the Companies submitted their annual ENEC update filing with the WVPSC proposing a $58 million annual increase in ENEC rates when compared to existing ENEC rates. The Companies proposed that this ENEC rate change would become effective September 1, 2024 and would include the recovery of $321 million of ENEC under-recovered costs as of February 28, 2023 over a ten-year period. In July 2024, intervenors and staff filed testimony with the WVPSC, which did not recommend any disallowances. 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.

2023 Virginia Base Rate Case

In March 2024, APCo filed a request with the Virginia SCC for a $95 million annual increase in base rates based upon a proposed 10.8% ROE and a proposed capital structure of 51% debt and 49% common equity. The requested increase in base rates is primarily due to incremental rate base, proposed capital structure changes including an increase in ROE and proposed increases in distribution and generation operation and maintenance expenses. In June 2024, APCo submitted an amendment to its Virginia base case filing with an updated request to increase annual base rates by $78 million. In July 2024, intervenors submitted testimony recommending a $14 million decrease in base rates based upon a 9.5% ROE. Staff testimony is due in August 2024 and a hearing is scheduled for September 2024. An order will be issued in the fourth quarter of 2024. 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.

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, 2024, AEP’s share of ETT’s cumulative revenues that are subject to a prudency review is approximately $1.8 billion. 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. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. ETT is required to file for a comprehensive rate review no later than February 1, 2025, during which the $1.8 billion of cumulative revenues above will be subject to review.

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

Michigan Power Supply Cost Recovery (PSCR)

2020 PSCR Reconciliation

In February 2023, the MPSC issued an order in I&M’s 2020 PSCR Reconciliation determining that the Michigan Code of Conduct pricing provisions apply to both the OVEC Inter-Company Power Agreement (ICPA) and I&M’s Rockport Plant UPA with AEGCo. The MPSC’s decision included a $1 million disallowance of 2020 purchase power costs associated with the OVEC ICPA with no disallowance related to I&M's Rockport UPA with AEGCo. I&M appealed the MPSC’s decision as it relates to the OVEC ICPA disallowance to the Michigan Supreme Court. In July 2024, the Michigan Supreme Court declined to hear I&M’s appeal.

2021 PSCR Reconciliation

In April 2023, I&M received intervenor testimony in I&M’s 2021 PSCR Reconciliation for the 12-month period ending December 31, 2021 recommending disallowances of purchased power costs of $18 million associated with the OVEC ICPA and the Rockport Plant UPA with AEGCo that were alleged to be above market in applying the MPSC’s Code of Conduct rules. Michigan staff submitted testimony in I&M’s 2021 PSCR Reconciliation with no recommended disallowances for PSCR costs incurred, including those associated with the OVEC ICPA and the Rockport Plant UPA with AEGCo. Michigan staff also recommended several options to address I&M’s shortfall in achieving Michigan’s annual one percent energy waste reduction savings level, resulting in potential future disallowed costs of up to approximately $14 million. In June 2023, Michigan staff submitted rebuttal testimony to update their calculation of the 2021 market proxy price resulting in a recommended disallowance of approximately $1 million related to the OVEC ICPA.

In April 2024, the MPSC issued an order on I&M’s 2021 PSCR Reconciliation that: (a) disallowed $1 million of purchased power costs associated with the OVEC ICPA that the MPSC concluded were above market, (b) disallowed $10 million of purchased power costs under the Rockport Plant UPA with AEGCo that the MPSC concluded were “energy only” and above market and (c) disallowed $497 thousand of PSCR costs due to I&M’s shortfall in achieving Michigan’s one percent energy waste reduction savings level in 2020. In May 2024, I&M filed a petition with the MPSC requesting a rehearing of the 2021 PSCR Reconciliation to: (a) address the method in which the disallowance of the purchased power costs under the Rockport Plant UPA with AEGCo was calculated, (b) explain why the disallowance was not appropriate and (c) explain how the MPSC-ordered disallowance was inconsistent with the previous MPSC orders approving Rockport Plant costs.

2022 PSCR Reconciliation

In January 2024, I&M received staff testimony in I&M’s 2022 PSCR Reconciliation for the 12-month period ending December 31, 2022 recommending disallowances of purchased power costs of $2 million associated with the OVEC ICPA that were alleged to be above market in applying the MPSC’s Code of Conduct rules. Similar to the 2021 PSCR Reconciliation, Michigan staff also recommended several options to address I&M’s shortfall in achieving Michigan’s annual one percent energy waste reduction savings level, resulting in potential future disallowed costs of up to approximately $6 million. In June 2024, an ALJ issued a Proposal for Decision (PFD) on I&M’s 2022 PSCR Reconciliation that recommended: (a) a $2 million disallowance of purchased power costs associated with the OVEC ICPA and (b) a disallowance of PSCR costs due to I&M’s shortfall in achieving Michigan’s one percent energy waste reduction savings level in 2022 consistent with the manner of the 2021 PSCR Reconciliation disallowance. An MPSC order on I&M’s 2022 PSCR Reconciliation is expected in the fourth quarter of 2024. If any PSCR costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2023 PSCR Reconciliation

In March 2024, I&M submitted its 2023 PSCR Reconciliation to the MPSC. The MPSC issued a procedural schedule with intervenor testimony due in October 2024. If any PSCR costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2023 Indiana Base Rate Case

In August 2023, I&M filed a request with the IURC for a $116 million annual increase in Indiana base rates based upon a 2024 forecasted test year, a proposed 10.5% ROE and a proposed capital structure of 48.8% debt and 51.2% common equity. I&M proposed that the annual increase in base rates be implemented in two steps, with the first increase effective in mid-2024, following an IURC order, and the second increase effective in January 2025. The proposed annual increase includes, but is not limited to, a $41 million increase related to depreciation expense, driven by increased depreciation rates and increased capital investments, and a $15 million increase related to storm expenses. I&M’s Indiana base case filing requested recovery of certain historical period regulatory asset balances and proposed deferral accounting for certain future investments and tax related issues, including CAMT expense and PTCs related to the Cook Plant.

In December 2023, I&M and intervenors reached a settlement agreement that was submitted to the IURC recommending a phased-in increase in Indiana rates with a $28 million annual increase effective upon an IURC order and the remaining $34 million annual increase effective in January 2025 subject to I&M’s level of electric plant in service as of December 31, 2024 in comparison to I&M’s 2024 forecasted test year. The recommended revenue increase includes: (a) a 9.85% ROE, (b) a two-step update of I&M’s Indiana capital structure with a capital structure of 50% for both debt and common equity effective upon an IURC order and a January 2025 update based on I&M’s actual capital structure as of December 31, 2024 with common equity not to exceed 51.2%, (c) a $25 million increase related to depreciation expense and (d) an $11 million increase related to storm expenses. In addition, I&M also agreed to withdraw its proposal to defer CAMT and Cook Plant PTCs.

In May 2024, the IURC issued an order approving the settlement agreement with minor modifications.

2023 Michigan Base Rate Case

In September 2023, I&M filed a request with the MPSC for a $34 million annual increase in Michigan base rates based upon a 2024 forecasted test year, a proposed 10.5% ROE and a capital structure of 49.4% debt and 50.6% common equity. The proposed annual increase includes an $11 million annual increase in depreciation expense driven by increased capital investment. I&M’s Michigan base case filing requests recovery of certain historical period regulatory asset balances and proposes deferral accounting for certain future investments and tax related issues, including CAMT expense and PTCs related to the Cook Plant.

In July 2024, the MPSC issued a final order approving an annual base rate increase of $17 million based on a 9.86% ROE and a capital structure of 52% debt and 48% common equity. The MPSC also ordered that Michigan jurisdictional Cook Plant PTCs will be reflected as a deferral in I&M’s PSCR reconciliation and rejected I&M’s request to defer Michigan jurisdictional CAMT.

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. In February 2024, KPCo filed a motion to strike and exclude intervenor testimony. In March 2024, the KPSC denied KPCo’s February 2024 motion. The June 2024 hearing with the KPSC 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 net income and cash flows and impact financial condition.

2023 Kentucky Base Rate and Securitization Case

In June 2023, KPCo filed a request with the KPSC for a $94 million net annual increase in base rates based upon a proposed 9.9% ROE with the increase to be implemented no earlier than January 2024. In conjunction with its June 2023 filing, KPCo further requested to finance through the issuance of securitization bonds, approximately $471 million of regulatory assets. KPCo’s proposal did not address the disposition of its 50% interest in Mitchell Plant, which will be addressed in the future. As of June 30, 2024, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $565 million. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In November 2023, KPCo filed an uncontested settlement agreement with the KPSC, that included an annual base rate increase of $75 million, based upon a 9.75% ROE. Settlement parties agreed that the KPSC should approve KPCo’s securitization request, and that the approximately $471 million regulatory assets requested for securitization are comprised of prudently incurred costs.

In January 2024, the KPSC issued an order modifying the November 2023 uncontested settlement agreement and approving an annual base rate increase of $60 million based upon a 9.75% ROE effective with billing cycles mid-January 2024. The order reduced KPCo’s base rate revenue requirement by $14 million to allow recovery of actual test year PJM transmission costs instead of KPCo’s requested annual level of costs based on PJM 2023 projected transmission revenue requirements. In February 2024, KPCo filed an appeal with the Commonwealth of Kentucky Franklin Circuit Court, challenging among other aspects of the order, the $14 million base rate revenue requirement reduction.

In January 2024, consistent with the November 2023 uncontested settlement agreement, the KPSC issued a financing order approving KPCo’s request to securitize certain regulatory assets balances as of the time securitization bonds are issued and concluding that costs requested for recovery through securitization were prudently incurred. The KPSC’s financing order includes certain additional requirements related to securitization bond structuring, marketing, placement and issuance that were not reflected in KPCo’s proposal. As a result, in January 2024, KPCo filed a request for rehearing with the KPSC to clarify certain aspects of these additional requirements. In February 2024, the KPSC denied KPCo’s rehearing requests. In accordance with Kentucky statutory requirements and the financing order, the issuance of the securitized bonds is subject to final review by the KPSC after bond pricing. KPCo expects to proceed with the securitized bond issuance process and to complete the securitization process in the second half of 2024, subject to market conditions. As of June 30, 2024, regulatory asset balances expected to be recovered through securitization total $481 million and include: (a) $293 million of plant retirement costs, (b) $79 million of deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, (c) $48 million of deferred purchased power expenses, (d) $60 million of under-recovered purchased power rider costs and (e) $1 million of deferred issuance-related expenses including KPSC advisor expenses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Fuel Adjustment Clause (FAC) Review

In December 2023, KPCo received intervenor testimony in its FAC review for the two-year period ending October 31, 2022, recommending a disallowance ranging from $44 million to $60 million of its total $432 million purchased power cost recoveries as a result of proposed modifications to the ratemaking methodology that limits purchased power costs recoverable through the FAC. A hearing was held in February 2024 and an order is expected in the second half of 2024 If any fuel costs are not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

Rockport Offset Recovery

In January 2024, KPCo filed an application with the KPSC seeking to recover an allowed cost (Rockport Offset) of $41 million in accordance with the terms of the settlement agreement in the 2017 Kentucky Base Rate Case permitting KPCo to use the level of non-fuel, non-environmental Rockport Plant UPA expense included in base rates to earn its authorized ROE in 2023 since the Rockport UPA ended in December 2022. An estimated Rockport Offset of $23 million was recovered through a rider, subject to true-up, during the 12-months ended December 2023. In February 2024, the KPSC issued an order allowing KPCo to collect the remaining $18 million through interim rates, subject to refund, over twelve months starting in March 2024. In April 2024, KPCo submitted to the KPSC a request for decision on the record. An order is expected in the second half of 2024. Through the second quarter of 2024, the Rockport Offset true-up is reflected in revenues to the extent amounts have been billed to customers, as KPCo has not met the requirements of alternative revenue recognition in accordance with the accounting guidance for “Regulated Operations”. If the Rockport Offset is not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters (Applies to AEP and OPCo)

OVEC Cost Recovery Audits

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

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. A hearing was held in November 2023. In the first quarter of 2024, post-hearing briefs were filed by the parties and the case currently awaits a decision on the merits.

Management disagrees with the intervenors’ claims and is unable to predict the impact of these disputes. If any costs are disallowed or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

Ohio ESP Filings

In January 2023, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments, proposed new riders and the continuation and modification of certain existing riders, including the DIR, effective June 2024 through May 2030. The proposal includes a return on common equity of 10.65% on capital costs for certain riders. In June 2023, intervenors filed testimony opposing OPCo’s plan for various new riders and modifications to existing riders, including the DIR. In September 2023, OPCo and certain intervenors filed a settlement agreement with the PUCO addressing the ESP application. The settlement included a four year term from June 2024 through May 2028, an ROE of 9.7% and continuation of a number of riders including the DIR subject to revenue caps. In April 2024, the PUCO issued an order approving the settlement agreement. In May 2024, intervenors filed an application for rehearing with the PUCO on the approved settlement agreement and in response OPCo filed an opposition to rehearing. In June 2024, the PUCO denied the intervenors’ application for rehearing.

PSO Rate Matters (Applies to AEP and PSO)

2024 Oklahoma Base Rate Case

In January 2024, PSO filed a request with the OCC for a $218 million annual base rate increase based upon a 10.8% ROE with a capital structure of 48.9% debt and 51.1% common equity. PSO requested an expanded transmission cost recovery rider and a mechanism to recover generation costs necessary to comply with SPP’s 2023 increased capacity planning reserve margin requirements. PSO’s request includes the 155 MW Rock Falls Wind Facility and reflects recovery of Northeastern Plant, Unit 3 through 2040.

In July 2024, OCC staff and various intervenors filed testimony. The OCC staff recommended a $115 million annual base rate increase based upon a 9.3% ROE while intervenors recommended an annual base rate increase ranging from $19 million to $113 million based on an ROE ranging from 9.0% to 9.6%. The OCC staff also recommended a $62 million disallowance of certain capital investments. In addition, a certain intervenor recommended the OCC reject PSO’s request to recover the Rock Falls Wind Facility through base rates, but allow PSO to retain PTCs and energy revenues up to the Rock Falls Wind Facility annual revenue requirement. A hearing is scheduled for September 2024 and an order is expected in the fourth quarter of 2024. 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)

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs.

Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory disallowance in 2013. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals.

In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap and remanded the case to the PUCT for future proceedings. In November 2021, SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. In June 2023, the Texas Supreme Court denied SWEPCo’s request for rehearing and the case was remanded to the PUCT for future proceedings. In October 2023, SWEPCo filed testimony with the PUCT in the remanded proceeding recommending no refund or disallowance.

On December 14, 2023, the PUCT approved a preliminary order stating the PUCT will not address SWEPCo’s request that would allow the PUCT to find cause to allow SWEPCo to exceed the Texas jurisdictional capital cost cap in the current remand proceeding. As a result of the PUCT’s approval of the preliminary order, SWEPCo believes it is probable the PUCT will disallow capitalized AFUDC in excess of the Texas jurisdictional capital cost cap and recorded a pretax, non-cash disallowance of $86 million. Such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis. On December 21, 2023, SWEPCo filed a motion with the PUCT for reconsideration of the preliminary order. In January 2024, the PUCT denied the motion for reconsideration of the preliminary order.

The PUCT’s December 2023 approval of the preliminary order determined that it will address, in the ongoing PUCT remand proceeding, any potential revenue refunds to customers that may be required by future PUCT orders. In January 2024, the PUCT established a procedural schedule for the remand proceeding. On March 1, 2024, SWEPCo filed supplemental direct testimony with the PUCT in response to the December 2023 preliminary order. On March 8, 2024, intervenors and the PUCT staff filed a motion with the PUCT to strike portions of SWEPCo’s October 2023 direct testimony and March 2024 supplemental direct testimony. On March 19, 2024, The ALJ granted portions of the motion, which included removal of testimony supporting SWEPCo’s position that refunds were not appropriate. On March 28, 2024, SWEPCo filed an appeal of the ALJ decision with the PUCT. In April 2024, intervenors and PUCT staff submitted testimony recommending customer refunds through December 2023 ranging from $149 million to $197 million, including carrying charges, with refund periods ranging from 18 months to 48 months. In May 2024, the PUCT denied SWEPCo’s appeal of the ALJ’s March 2024 decision. In the second quarter of 2024, based on the PUCT’s decision, SWEPCo recorded a one-time, probable revenue refund provision of $160 million, including interest, associated with revenue collected from February 2013 through December 2023. The $160 million revenue refund provision represents management’s best estimate based on the range of probable refunds between $104 million and $197 million, including interest. In June 2024, SWEPCo and parties to the remand proceeding reached an agreement in principle that would resolve all issues in the case. The settlement is expected to be filed and considered by the PUCT in the third quarter of 2024.

2016 Texas Base Rate Case

In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a 9.6% ROE, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in-service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.

As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors related to limiting SWEPCo’s recovery of AFUDC on Turk Plant and recovery of Welsh Plant, Unit 2. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition.

2020 Texas Base Rate Case

In October 2020, SWEPCo filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $100 million, which would result in an $85 million net annual base rate increase after moving the proposed riders to rate base.

In January 2022, the PUCT issued a final order approving an annual revenue increase of $39 million based upon a 9.25% ROE. The order also includes: (a) rates implemented retroactively back to March 18, 2021, (b) $5 million of the proposed increase related to vegetation management, (c) $2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider to recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value to be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $12 million in 2021 associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the order, which include challenges of the approved ROE, the denial of a reasonable return or carrying costs on the Dolet Hills Power Station and the calculation of the Texas jurisdictional share of the storm catastrophe reserve. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking judicial review of the several errors challenged in the PUCT’s final order.

2021 Louisiana Storm Cost Filing

In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC, which confirmed the prudency of $150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125% through March 2024. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. In April 2024, SWEPCo and the LPSC staff filed a joint uncontested stipulation and settlement agreement with the LPSC requesting securitization of storm costs, including a storm reserve. In July 2024, the LPSC issued an order approving the joint uncontested stipulation and settlement agreement, including approval to securitize $343 million, which includes $180 million for storm costs and a $150 million storm reserve.

February 2021 Severe Winter Weather Impacts in SPP

In February 2021, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021 to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are shown in the table below:

(a)SWEPCo is permitted to record carrying costs on the unrecovered balance of fuel costs at a weighted-cost of capital approved by the APSC. The APSC will conclude an audit of these costs in 2024. A hearing was held in June 2024.

(b)In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge equal to the prime rate. The special order states the fuel and purchased power costs incurred will be subject to a future LPSC audit.

If SWEPCo is unable to recover any of the costs relating to the extraordinary fuel and purchases of electricity, or obtain authorization of a reasonable carrying charge on these costs, 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

The NCWF are subject to various regulatory performance requirements, including a Net Capacity Factor (NCF) guarantee. The NCF guarantee will be measured 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 have experienced performance issues related to defects covered by the manufacturer’s warranty. These performance issues have prompted PSO and SWEPCo to file a lawsuit against the manufacturer in an attempt to find a resolution on the matter. If regulatory performance requirements, such as the NCF guarantee, are not met, PSO and SWEPCo may recognize a regulatory liability to refund retail customers. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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 Certificate of Public Convenience and Necessity 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. Additional regulatory proceedings before the PAPUC are expected to resume in the fourth quarter of 2024 or in 2025.

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 has not been cancelled and remains necessary to alleviate congestion. PJM continues to evaluate reliability and market efficiency in the area. As of June 30, 2024, AEP’s share of IEC capital expenditures was approximately $94 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 cancelled 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.

Request to Update AEGCo Depreciation Rates (Applies to AEP and I&M)

In October 2022, AEP, on behalf of AEGCo, submitted proposed revisions to AEGCo’s depreciation rates for its 50% ownership interest in Rockport Plant, Unit 1 and Unit 2, reflected in the UPA between AEGCo and I&M. The proposed depreciation rates for these assets reflect an estimated 2028 retirement date for the Rockport Plant. AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 1 were based upon a December 31, 2028 estimated retirement date while AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 2 leasehold improvements were based upon a December 31, 2022 estimated retirement date in conjunction with the termination of the Rockport Plant, Unit 2 lease.

In December 2022, the FERC issued an order approving the proposed AEGCo Rockport depreciation rates effective January 1, 2023, subject to further review and a potential refund. In August 2023, AEGCo reached a settlement agreement with the FERC trial staff that resolved all issues set for hearing. In September 2023, the settlement agreement was certified to the FERC as uncontested. In March 2024, the FERC issued an order approving the uncontested settlement agreement. The results of the order did not have a material impact on financial condition, results of operations or cash flows.

FERC 2021 PJM and SPP Transmission Formula Rate Challenge (Applies to AEP, AEPTCo, APCo, I&M, PSO and SWEPCo)

The Registrants transitioned to stand-alone treatment of NOLCs in its 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. Stand-alone treatment of the NOLCs for transmission formula rates increased the annual revenue requirements for years 2024, 2023, 2022 and 2021 by $52 million, $60 million, $69 million and $78 million, respectively.

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. 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 request 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. AEPSC is required to file briefs with the FERC in the third quarter of 2024.

As a result of the January 2024 FERC orders, the Registrants’ balance sheets reflect a liability for the probable refund of all NOLC revenues included in transmission formula rates for years 2024, 2023, 2022 and 2021, with interest. The Registrants have not yet been directed to make cash refunds related to the 2024, 2023 or 2022 rate years. The probable refunds to affiliated and nonaffiliated customers are reflected as Deferred Credits and Other Noncurrent Liabilities on the balance sheets, with the exception of amounts expected to be refunded within one year which are reflected in Other Current Liabilities. Refunds probable to be received by affiliated companies, resulting in a reduction to affiliated transmission expense, were deferred as an increase to Regulatory Liabilities or a reduction to Regulatory Assets on the balance sheets where management expects that refunds would be returned to retail customers through authorized retail jurisdiction rider mechanisms.

Request to Update SWEPCo Generation Depreciation Rates (Applies to AEP and SWEPCo)

In October 2023, SWEPCo filed an application to revise its generation wholesale customer’s contracts to reflect an increase in the annual revenue requirement of approximately $5 million for updated depreciation rates and allow for the return on and of FERC customers jurisdictional share of regulatory assets associated with retired plants. In November 2023, certain intervenors filed a motion with the FERC protesting and recommending the rejection of SWEPCo’s filings. In December 2023, the FERC issued an order approving the proposed rates effective January 1, 2024, subject to further review and refund and established hearing and settlement proceedings. If SWEPCo is unable to recover the remaining regulatory assets associated with retired plants, it could reduce future net income and cash flows and impact financial condition.

5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2023 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit (Applies to AEP, AEP Texas and APCo)

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 March 2024, AEP increased its $4 billion revolving credit facility to $5 billion and extended the due date from March 2027 to March 2029. Also, in March 2024, AEP extended the due date of its $1 billion revolving credit facility from March 2025 to March 2027. 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, 2024, 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 six uncommitted facilities totaling $450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of June 30, 2024 were as follows:

Indemnifications and Other Guarantees

Contracts

The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of June 30, 2024, there were no material liabilities recorded for any indemnifications.

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

Master Lease Agreements (Applies to all Registrants except AEPTCo)

The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed. As of June 30, 2024, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

Federal EPA’s Revised CCR Rule

In April 2024, the Federal EPA finalized revisions to the CCR Rule 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 existing CCR Rule requirements applicable to inactive CCR surface impoundments at active facilities, except for the location restrictions and liner design criteria. The rule establishes compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within five years after the effective date of the final rule. The rule requires evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. Closure may be accomplished by applying an impermeable cover system over the CCR material (“closure in place”) or the CCR material may be excavated and placed in a compliant landfill (“closure by removal”). Groundwater monitoring and other analysis over the next three years will provide additional information on the planned closure method. AEP evaluated the applicability of the rule to current and former plant sites and recorded incremental ARO in the second quarter of 2024, as shown in the table below, based on initial cost estimates primarily reflecting compliance with the rule through closure in place and future groundwater monitoring requirements pursuant to the CCR Rule.