AEP 10-Q Quarter ended June 30, 2025

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The disclosures in this note apply to all Registrants unless indicated otherwise.

General

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

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant.  Net income for the three and six months ended June 30, 2025 is not necessarily indicative of results that may be expected for the year ending December 31, 2025.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2024 financial statements and notes thereto, which are included in the 2024 Annual Reports.

Earnings Per Share (EPS) (Applies to AEP)

Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted-average number of common shares outstanding during the period.  Diluted EPS is calculated by adjusting the weighted-average outstanding common shares, assuming conversion of all potentially dilutive securities. Dilutive securities are primarily related to forward sale of equity agreements and restricted stock units. See Note 13 - Financing Activities for more information regarding the forward sale of equity agreements.

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

			Three Months Ended June 30,
			2025												2024
			(in millions, except per share data)
									$/share												$/share
Earnings Attributable to AEP Common Shareholders			$	1,225.8											$	340.3
Weighted-Average Number of Basic AEP Common Shares Outstanding			534.3						$	2.29					528.9						$	0.64
Weighted-Average Dilutive Effect			2.1						—						1.2						—
Weighted-Average Number of Diluted AEP Common Shares Outstanding			536.4						$	2.29					530.1						$	0.64

			Six Months Ended June 30,
			2025												2024
			(in millions, except per share data)
									$/share												$/share
Earnings Attributable to AEP Common Shareholders			$	2,026.0											$	1,343.4
Weighted-Average Number of Basic AEP Common Shares Outstanding			533.8						$	3.80					527.7						$	2.55
Weighted-Average Dilutive Effect			1.7						( 0.02 )						1.2						( 0.01 )
Weighted-Average Number of Diluted AEP Common Shares Outstanding			535.5						$	3.78					528.9						$	2.54

There were no antidilutive shares outstanding as of June 30, 2025 and 2024.

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

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

Reconciliation of Cash, Cash Equivalents and Restricted Cash

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

						June 30, 2025
						AEP						AEP Texas						APCo						SWEPCo
						(in millions)
Cash and Cash Equivalents						$	227.3					$	0.1					$	6.2					$	3.7
Restricted Cash						51.3						13.3						18.2						16.7
Total Cash, Cash Equivalents and Restricted Cash						$	278.6					$	13.4					$	24.4					$	20.4

						December 31, 2024
						AEP						AEP Texas						APCo						SWEPCo
						(in millions)
Cash and Cash Equivalents						$	202.9					$	0.1					$	3.9					$	1.2
Restricted Cash						43.1						23.5						16.2						3.4
Total Cash, Cash Equivalents and Restricted Cash						$	246.0					$	23.6					$	20.1					$	4.6

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The disclosures in this note apply to all Registrants unless indicated otherwise.

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

SEC Climate Disclosure Rule

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 a registrant’s board of directors oversight and management’s role in managing material climate-related risks. The final rules also require registrants to provide information related to any climate-related targets or goals that are material to a 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. On March 27, 2025, the SEC announced that it voted to end its defense of the final climate disclosure rules. On April 3, 2025, 18 states filed a motion to intervene in the case and to hold the case in abeyance until the SEC takes action to amend or rescind the rules. The Registrants are currently evaluating the status of the rules and the impact of the final rules on their respective consolidated financial statements and related disclosures.

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 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.

Management adopted ASU 2023-07 and its related implementation guidance effective January 1, 2024 for the annual reporting period and applied the amendments retrospectively to all prior periods presented in the annual consolidated financial statements. The amendments for interim periods were adopted in the fiscal year beginning on January 1, 2025. The adoption of the new standard did not impact the results of operations, statements of financial position or cash flows. See Note 8 - Business Segments for additional information.

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.

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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 will adopt the amendments to this standard prospectively beginning with the Annual Report on Form 10-K for the fiscal year ending December 31, 2025.

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

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

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

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

Presentation of Comprehensive Income

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

						Cash Flow Hedges												Pension
Three Months Ended June 30, 2025						Commodity						Interest Rate						and OPEB						Total
						(in millions)
Balance in AOCI as of March 31, 2025						$	123.7					$	1.2					$	( 104.6 )					$	20.3
Change in Fair Value Recognized in AOCI, Net of Tax						( 36.0 )						—						—						( 36.0 )
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)						4.8						—						—						4.8
Interest Expense (a)						—						( 1.2 )						—						( 1.2 )
Amortization of Prior Service Cost (Credit)						—						—						( 0.3 )						( 0.3 )
Amortization of Actuarial (Gains) Losses						—						—						0.6						0.6
Reclassifications from AOCI, before Income Tax (Expense) Benefit						4.8						( 1.2 )						0.3						3.9
Income Tax (Expense) Benefit						1.0						( 0.2 )						—						0.8
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit						3.8						( 1.0 )						0.3						3.1
Net Current Period Other Comprehensive Income (Loss)						( 32.2 )						( 1.0 )						0.3						( 32.9 )
Balance in AOCI as of June 30, 2025						$	91.5					$	0.2					$	( 104.3 )					$	( 12.6 )

						Cash Flow Hedges												Pension
Three Months Ended June 30, 2024						Commodity						Interest Rate						and OPEB						Total
						(in millions)
Balance in AOCI as of March 31, 2024						$	87.2					$	3.4					$	( 152.9 )					$	( 62.3 )
Change in Fair Value Recognized in AOCI, Net of Tax						7.0						6.9						—						13.9
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)						11.8						—						—						11.8
Interest Expense (a)						—						( 1.1 )						—						( 1.1 )
Amortization of Prior Service Cost (Credit)						—						—						( 1.3 )						( 1.3 )
Amortization of Actuarial (Gains) Losses						—						—						1.2						1.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit						11.8						( 1.1 )						( 0.1 )						10.6
Income Tax (Expense) Benefit						2.3						( 0.1 )						—						2.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit						9.5						( 1.0 )						( 0.1 )						8.4
Net Current Period Other Comprehensive Income (Loss)						16.5						5.9						( 0.1 )						22.3
Balance in AOCI as of June 30, 2024						$	103.7					$	9.3					$	( 153.0 )					$	( 40.0 )

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						Cash Flow Hedges												Pension
Six Months Ended June 30, 2025						Commodity						Interest Rate						and OPEB						Total
						(in millions)
Balance in AOCI as of December 31, 2024						$	98.5					$	3.3					$	( 104.9 )					$	( 3.1 )
Change in Fair Value Recognized in AOCI, Net of Tax						2.2						( 1.0 )						—						1.2
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)						( 11.7 )						—						—						( 11.7 )
Interest Expense (a)						—						( 2.6 )						—						( 2.6 )
Amortization of Prior Service Cost (Credit)						—						—						( 0.4 )						( 0.4 )
Amortization of Actuarial (Gains) Losses						—						—						1.1						1.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit						( 11.7 )						( 2.6 )						0.7						( 13.6 )
Income Tax (Expense) Benefit						( 2.5 )						( 0.5 )						0.1						( 2.9 )
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit						( 9.2 )						( 2.1 )						0.6						( 10.7 )
Net Current Period Other Comprehensive Income (Loss)						( 7.0 )						( 3.1 )						0.6						( 9.5 )
Balance in AOCI as of June 30, 2025						$	91.5					$	0.2					$	( 104.3 )					$	( 12.6 )

						Cash Flow Hedges												Pension
Six Months Ended June 30, 2024						Commodity						Interest Rate						and OPEB						Total
						(in millions)
Balance in AOCI as of December 31, 2023						$	104.9					$	( 8.1 )					$	( 152.3 )					$	( 55.5 )
Change in Fair Value Recognized in AOCI, Net of Tax						12.5						19.3						—						31.8
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)						( 17.5 )						—						—						( 17.5 )
Interest Expense (a)						—						( 2.3 )						—						( 2.3 )
Amortization of Prior Service Cost (Credit)						—						—						( 2.6 )						( 2.6 )
Amortization of Actuarial (Gains) Losses						—						—						1.7						1.7
Reclassifications from AOCI, before Income Tax Expense						( 17.5 )						( 2.3 )						( 0.9 )						( 20.7 )
Income Tax Expense						( 3.8 )						( 0.4 )						( 0.2 )						( 4.4 )
Reclassifications from AOCI, Net of Income Tax Expense						( 13.7 )						( 1.9 )						( 0.7 )						( 16.3 )
Net Current Period Other Comprehensive Income (Loss)						( 1.2 )						17.4						( 0.7 )						15.5
Balance in AOCI as of June 30, 2024						$	103.7					$	9.3					$	( 153.0 )					$	( 40.0 )

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

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The disclosures in this note apply to all Registrants unless indicated otherwise.

As discussed in the 2024 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2024 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 2025 and updates the 2024 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 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. SWEPCo requested recovery including a weighted average cost of capital carrying charge in its Arkansas base rate case filed in March 2025. In July 2023, Texas ALJs issued a PFD that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected the ALJs’ July 2023 PFD. 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, 2025, the Texas jurisdictional share of the net book value of the Pirkey Plant was $ 76 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. Following the 2024 Oklahoma Base Rate Case, PSO continues to recover Northeastern Plant, Unit 3 through 2040. In April 2025, PSO and the ODEQ finalized a second amended regional haze agreement that would allow continued operation of the Northeastern Plant, Unit 3, on natural gas, through May 31, 2041. This agreement is contingent upon approval by the Federal EPA in the form of a revised SIP. The ODEQ is in the process of preparing a SIP submission for the Federal EPA’s review and approval.

SWEPCo

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

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The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of June 30, 2025, of generating facilities planned for early retirement:

Plant																		Net Book Value						Accelerated Depreciation Regulatory Asset												Cost of Removal Regulatory Liability									Projected Retirement Date									Current Authorized Recovery Period						Annual Depreciation (a)
																		(dollars in millions)
Northeastern Plant, Unit 3																		$	79.8					$	204.7											$	21.1		(b)						2026									(c)						$	16.7
Welsh Plant, Units 1 and 3																		300.9						192.7												57.7			(d)						2028			(e)						(f)						45.9

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

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

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

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

(e) Represents projected retirement date of coal assets.

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

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, 2025, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $ 70 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, 2025, SWEPCo had a net under-recovered fuel balance of $ 26 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.

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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, 2025, SWEPCo’s share of the net investment in the Pirkey Plant was $ 204 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, 2025, SWEPCo had a net under-recovered fuel balance of $ 26 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. In April 2025, the LPSC determined the retirement of the Pirkey Plant was reasonable and prudent and authorized continued recovery of and on the remaining balance of the Pirkey Plant at SWEPCo’s weighted average cost of capital through 2032.

In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $ 33 million of Sabine related fuel costs through 2035. In June 2024, SWEPCo filed a fuel reconciliation with the PUCT for its retail operation in Texas for the period of January 2022 through December 2023. The fuel reconciliation included approximately $ 535 million in Texas jurisdictional eligible fuel costs. In January 2025, intervenors filed testimony recommending a disallowance of Texas jurisdictional fuel costs ranging from $ 2 million to $ 33 million related to SWEPCo’s decision to retire the Pirkey Plant, management of fuel inventory and SWEPCo’s energy price offers in SPP. In April 2025, a settlement agreement was filed with the PUCT resolving the issues in the case and resulting in a one-time $ 6 million disallowance of fuel costs. An order is expected in 2025.

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.

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

						AEP
						June 30,						December 31,
						2025						2024
Noncurrent Regulatory Assets						(in millions)
Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation						$	192.7					$	168.6
Pirkey Plant Accelerated Depreciation						132.6						121.3
Unrecovered Winter Storm Fuel Costs (a)						55.9						70.7
Storm-Related Costs						53.8						51.0
AEP Texas House Bill 5247						25.0						—
Other Regulatory Assets Pending Final Regulatory Approval						26.5						20.7
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs (b)						378.3						357.4
Storm-Related Costs						310.5						300.8
2024-2025 Virginia Biennial Under-Earnings						156.5						78.4
NOLC Costs (c)						88.8						92.8
Other Regulatory Assets Pending Final Regulatory Approval						107.3						86.3
Total Regulatory Assets Pending Final Regulatory Approval						$	1,527.9					$	1,348.0

(a) Includes $ 37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of June 30, 2025 and December 31, 2024, respectively. See “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.

(c) See “NOLCs in Retail Jurisdictions - IRS PLRs” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

						AEP Texas
						June 30,						December 31,
						2025						2024
Noncurrent Regulatory Assets						(in millions)
Regulatory Assets Currently Earning a Return
Storm-Related Costs						$	41.3					$	41.3
AEP Texas House Bill 5247						25.0						—
Other Regulatory Assets Pending Final Regulatory Approval						1.2						—
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs						30.9						13.1
Deferred Pension and OPEB Costs						21.7						15.6
Line Inspection Costs						5.8						5.8
Other Regulatory Assets Pending Final Regulatory Approval						1.4						1.3
Total Regulatory Assets Pending Final Regulatory Approval						$	127.3					$	77.1

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						APCo
						June 30,						December 31,
						2025						2024
Noncurrent Regulatory Assets						(in millions)
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval						$	1.3					$	1.1
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs (a)						299.4						282.1
Storm-Related Costs – West Virginia						163.2						144.2
2024-2025 Virginia Biennial Under-Earnings						156.5						78.4
Pension Settlement						17.1						17.8
Other Regulatory Assets Pending Final Regulatory Approval						20.9						11.9
Total Regulatory Assets Pending Final Regulatory Approval						$	658.4					$	535.5

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

						I&M
						June 30,						December 31,
						2025						2024
Noncurrent Regulatory Assets						(in millions)
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval						$	6.7					$	6.4
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs (a)						76.2						74.0
Storm-Related Costs – Indiana						24.0						6.3
NOLC Costs – Indiana (b)						—						26.7
Other Regulatory Assets Pending Final Regulatory Approval						1.9						1.6
Total Regulatory Assets Pending Final Regulatory Approval						$	108.8					$	115.0

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

(b) See “NOLCs in Retail Jurisdictions - IRS PLRs” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

						OPCo
						June 30,						December 31,
						2025						2024
Noncurrent Regulatory Assets						(in millions)
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval						$	0.7					$	0.4
Regulatory Assets Currently Not Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval						—						0.1
Total Regulatory Assets Pending Final Regulatory Approval						$	0.7					$	0.5

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						PSO
						June 30,						December 31,
						2025						2024
Noncurrent Regulatory Assets						(in millions)
Regulatory Assets Currently Not Earning a Return
NOLC Costs (a)						$	23.2					$	16.4
Storm-Related Costs						21.3						4.9
Pension Settlement						7.5						7.8
Other Regulatory Assets Pending Final Regulatory Approval						9.5						1.2
Total Regulatory Assets Pending Final Regulatory Approval						$	61.5					$	30.3

(a) See “NOLCs in Retail Jurisdictions - IRS PLRs” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

						SWEPCo
						June 30,						December 31,
						2025						2024
Noncurrent Regulatory Assets						(in millions)
Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation						$	192.7					$	168.6
Pirkey Plant Accelerated Depreciation						132.6						121.3
Unrecovered Winter Storm Fuel Costs (a)						55.9						70.7
Dolet Hills Power Station Accelerated Depreciation (b)						12.0						11.8
Other Regulatory Assets Pending Final Regulatory Approval						17.1						10.8
Regulatory Assets Currently Not Earning a Return
NOLC Costs (c)						65.6						49.6
Storm-Related Costs - Louisiana, Texas						45.9						39.9
Other Regulatory Assets Pending Final Regulatory Approval						18.7						18.7
Total Regulatory Assets Pending Final Regulatory Approval						$	540.5					$	491.4

(a) Includes $ 37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of June 30, 2025 and December 31, 2024 , respectively. See “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.

(b) Amounts include the FERC jurisdiction.

(c) See “NOLCs in Retail Jurisdictions - IRS PLRs” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

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

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

AEP Texas Interim Transmission and Distribution Rates

Through June 30, 2025, AEP Texas’ cumulative revenues from transmission and distribution interim base rate increases that are subject to review are estimated to be approximately $ 43 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition.

Texas Legislation

On June 20, 2025, Texas House Bill 5247 (HB 5247) was signed into law by the Governor of Texas and became effective. The bill establishes a tracking mechanism for qualifying electric utilities to file annual interim rate adjustments for cost recovery of certain transmission and distribution capital expenditures. On June 27, 2025, AEP Texas filed with the PUCT notice of qualification and election to follow the new methodology as permitted by HB 5247. Qualifying electric utilities under HB 5247 consist of utilities that: (a) operate solely in ERCOT, (b) have been identified by the PUCT as having responsibility for constructing transmission infrastructure as part of ERCOT’s Permian Basin Reliability Plan and (c) make annual capital expenditures in transmission and distribution that exceed 300% of annual depreciation. Based on those requirements, AEP Texas is a qualifying electric utility and SWEPCo and ETT are not qualifying electric utilities.

The tracking mechanism permits a qualifying electric utility to defer all or a portion of costs associated with its eligible transmission and distribution capital investments, including depreciation expense and carrying costs, as a regulatory asset. The tracking mechanism is available through 2035 and is an alternative to the existing capital tracking mechanisms in Texas. Deferred costs will be recovered through interim rate updates over a period not to exceed 18 months and earn a return until recovered. As a result of the new legislation, AEP Texas deferred approximately $ 25 million of eligible costs through June 2025 as a regulatory asset. Investments included in the tracking mechanism and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate review before the PUCT. If any of these deferred costs are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

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

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 % debt carrying charge rate over a ten-year recovery period starting September 1, 2024.

In February 2024, the Companies filed briefs with the West Virginia Supreme Court (WVSC) to initiate an appeal of the January 2024 order. Following arguments that were held in September 2024, the WVSC issued a November 2024 opinion affirming in part and reversing in part the WVPSC’s January 2024 ENEC order. The WVSC remanded the ENEC case to the WVPSC to afford the Companies an opportunity to examine, analyze, rebut and refute the calculation of the $ 232 million disallowance. In March 2025, the WVPSC entered an order in the Companies’ 2021-2023 ENEC cases further describing its calculations of the ordered $ 232 million disallowance. In June 2025, the Companies submitted direct testimony on remand supporting a reduction to the WVPSC’s previously-ordered disallowance of at least $ 179 million. Staff and intervenor testimony is due in August 2025 and a hearing is scheduled for October 2025.

In April 2024, the Companies submitted their 2024 ENEC update case proposing a $ 58 million annual increase in ENEC rates when compared to existing ENEC rates. The Companies proposed that this ENEC rate change would: (a) become effective September 1, 2024, (b) include a $ 20 million annual increase in ENEC rates related to the period ending February 29, 2024 and the forecast period September 2024 through August 2025 and (c) include a $ 38 million annual increase in ENEC rates for the recovery of $ 321 million of ENEC under-recovered costs as of February 28, 2023 over a ten-year period, plus a 4 % debt carrying charge rate. In August 2024, the WVPSC issued an order approving the requested $ 38 million annual increase effective September 1, 2024. In March 2025, the WVPSC issued an order approving the requested $ 20 million annual increase effective March 11, 2025.

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In April 2025, the Companies submitted their 2025 ENEC update filing proposing a $ 72 million annual increase in ENEC rates. In July 2025, WVPSC staff and intervenors filed testimony, and one intervening party recommended a disallowance of approximately $ 19 million.

If any ENEC costs are not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

Virginia Fuel Adjustment Clause (FAC) Review

In 2023, APCo submitted its annual fuel cost filing with the Virginia SCC. Interim Virginia FAC rates were implemented in November 2023. In APCo's 2022 Virginia fuel update filing, the Virginia SCC ordered the Virginia Staff to commence an audit of APCo’s fuel costs for the years ended December 31, 2019, 2020, 2021 and 2022. The Virginia staff analyzed APCo’s 2019 through 2022 fuel procurement activities and concluded the procurement practices were reasonable and prudent and recommended no disallowances. In May 2024, the Virginia SCC issued an order approving the audit of APCo’s 2019 and 2020 fuel costs but concluded that the review of APCo fuel costs for 2021 and 2022 remains open for further evaluation as part of APCo’s 2024 fuel cost filing.

In September 2024, APCo submitted its annual Virginia fuel cost filing with the Virginia SCC proposing no change in annual APCo Virginia FAC rates charged to customers. In January 2025, an intervening party recommended a minimum fuel under-recovery disallowance of $ 20 million related to alleged imprudent operations of Amos and Mountaineer generating units during October 2021 and November 2021. There were no other recommended disallowances by intervenors or Virginia Staff regarding APCo’s historical period Virginia fuel under-recovery balance through October 31, 2024. Virginia Staff recommended that the Virginia SCC close APCo’s open review periods related to 2021 and 2022 Virginia fuel costs. A hearing was held in February 2025. In March 2025, the Hearing Examiner re-opened the record to obtain additional information to resolve certain issues. In April 2025, APCo and an intervenor submitted supplemental testimony with the intervenor continuing to recommend a $ 20 million disallowance. A hearing was held in May 2025. In June 2025, the Hearing Examiner issued a report recommending no disallowance. An order is anticipated from the Virginia SCC in the third quarter of 2025.

If any fuel costs are not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

2024 West Virginia Base Rate Case

In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $ 251 million annual increase in base rates based upon a proposed 10.8 % ROE and a proposed capital structure of 52 % debt and 48 % common equity. The requested net annual increase in base rates excludes the Companies’ proposed $ 94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $ 21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $ 118 million in previously deferred major storm expenses over a three-year period plus a carrying charge on the deferral balance, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses.

The Companies’ November 2024 West Virginia base rate filing also included two sets of alternative frameworks to simplify rates and customer bills and provide predictable future rate increases. The Companies’ first framework includes: (a) securitization, (b) approval of a major storm expense recovery and tracking mechanism and (c) freezing of OATT revenues in the ENEC. This framework includes securitization in a concurrent proceeding of approximately $ 2.4 billion of West Virginia jurisdictional assets. Securitization of those items could reduce the Companies’ combined requested increase in annual base rates to $ 37 million. See the “2025 West Virginia Securitization Filing” section below for additional information.

The Companies also included an alternative ratemaking proposal that includes: (a) a separate surcharge that would allow the Companies up to a 3 % annual increase in overall West Virginia rates for four consecutive years on April 1 st of each year after the implementation of base rates in this case, (b) the elimination of all of the Companies’ existing West Virginia jurisdictional surcharges except for the ENEC, with the revenues of these eliminated riders rolled into base rates and (c) the creation of a new West Virginia jurisdictional environmental and new generation surcharge. This alternative proposal would allow the Companies to submit a base rate case filing in advance of and in lieu of the annual April 1st 3 % increase and would require the Companies to submit a base rate case filing at the end of the proposed four-year period.

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In April 2025, a hearing was held at the WVPSC to review the Companies’ separate depreciation filing. Also in April 2025, WVPSC staff and intervenors submitted testimony regarding the Companies’ base rate filing recommending combined APCo and WPCo base rate increases ranging from $ 49 million to $ 91 million based on proposed ROEs ranging from 9.1 % to 9.25 %. In May 2025, the combined APCo and WPCo base rate increases range was revised to $ 49 million to $ 72 million. These base rate recommendations included significant decreases in rate base for the use of a 13-month average rate base rather than a year-end rate base as proposed by the Companies, and also included various reductions to the Companies’ proposed ongoing levels of depreciation expense and other operation and maintenance expenses. WVPSC staff recommended that the WVPSC approve the Companies’ requested recovery of $ 118 million of deferred extraordinary storm costs over a five-year period rather than the proposed three-year recovery period, while also recommending that the WVPSC reject the Companies’ proposal of a carrying charge on the storm deferral balance if the recovery is more than three years . WVPSC staff and an intervenor also recommended that the WVPSC deny the ratemaking impact of NOLC and reject the Companies’ request to continue the MRBC surcharge. In May 2025, the Companies filed rebuttal testimony supporting a net $ 224 million annual increase in base rates. A hearing was held at the WVPSC in June 2025 and an order is expected in the third quarter of 2025.

For the Companies’ first proposed alternative ratemaking framework described above, WVPSC staff and intervenors recommended that the WVPSC: a) consider securitization subject to certain conditions, b) approve the Companies’ proposed major storm deferral accounting for major storm other operation and maintenance expenses against the level embedded in the development of base rates, and c) reject the proposed freeze of OATT revenues in the ENEC. WVPSC staff and intervenors generally recommended that the WVPSC reject the Companies’ second proposed alternative ratemaking framework described above.

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.

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

In March 2024, APCo and WPCo (the Companies) submitted an annual MRBC surcharge update filing with the WVPSC requesting a $ 32 million annual increase in the Companies’ combined MRBC rates. The MRBC is an infrastructure investment tracker that allows limited cost recovery related to capital investments between the Companies’ West Virginia jurisdictional base rate cases. WVPSC staff and an intervening party recommended revenue requirement disallowances in written and verbal testimony and briefs for certain ratemaking issues used to develop the Companies’ proposed MRBC rates, including the West Virginia jurisdictional effect of state deferred income taxes, NOLC and AROs. In July 2025, the WVPSC issued an order stating that a ruling on the Companies’ 2024 MRBC surcharge update filing and all contested issues will be included in the August 2025 order on the Companies’ 2024 West Virginia base case filing. If any refund liabilities are imposed by the WVPSC, it could reduce future net income and cash flows and impact financial condition.

2025 West Virginia Securitization Filing

In March 2025, APCo and WPCo (the Companies) requested to finance, through the issuance of securitization bonds, approximately $ 2.4 billion of West Virginia jurisdictional undepreciated property balances and regulatory assets including: (a) $ 321 million of the Companies’ remaining combined unrecovered ENEC balance related to costs incurred through February 28, 2023, (b) $ 1.7 billion of undepreciated West Virginia jurisdictional plant balances as of December 31, 2022 for the Amos, Mitchell and Mountaineer Plants, (c) $ 237 million of environmental costs previously approved for recovery through a separate West Virginia surcharge and (d) $ 118 million of West Virginia jurisdictional major storm operation and maintenance costs deferred as of June 2024. The proposed securitized items breakout for the Companies is shown in the table below:

Proposed Securitized Items						APCo						WPCo						Total
						(in millions)
Undepreciated Utility Plant Balances of Amos, Mitchell and Mountaineer (as of December 31, 2022)						$	1,145.5					$	558.7					$	1,704.2
ENEC Under-Recovery Regulatory Assets (as of February 28, 2023)						174.3						146.8						321.1
Forecasted Undepreciated CCR and ELG Investments of Amos, Mitchell and Mountaineer (as of November 30, 2024)						87.6						149.2						236.8
Deferred Storm O&M Expense Regulatory Assets (as of June 30, 2024)						115.0						2.9						117.9
Upfront Financing Costs						10.1						5.7						15.8
Total						$	1,532.5					$	863.3					$	2,395.8

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The Companies also proposed that the WVPSC consider approving the securitization of additional ENEC under-recovered costs, such as those costs approved in the 2024 ENEC case, as well as additional deferred West Virginia jurisdictional major storm operation and maintenance costs, such as those associated with Hurricane Helene and Winter Storms Blair, Harlow and Jett.

In May 2025, WVPSC staff recommended that the $ 321 million ENEC under-recovery and $ 118 million storm cost deferral be excluded from the securitization. Staff recommended that the $ 321 million ENEC under-recovery continue to be recovered through the current ENEC rates and the storm cost deferral be recovered without a carrying charge over five years through base rates to be implemented in August 2025. A hearing was held in July 2025 and an order is expected in the third quarter of 2025.

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

2025 Virginia Securitization Filing

In July 2025, APCo filed a request with the Virginia SCC to finance, through the issuance of securitization bonds, approximately $ 1.4 billion of Virginia jurisdictional undepreciated property balances and a major storm operation and maintenance regulatory asset deferral balance. This proposed securitization included: (a) $ 1.2 billion of undepreciated Virginia jurisdictional plant balances as of December 31, 2023 for the Amos and Mountaineer Plants and (b) $ 141 million of Virginia jurisdictional major storm other operation and maintenance expenses deferred during the 2024-2025 biennial period.

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, 2025, AEP’s share of ETT’s cumulative revenues from interim base rate increases that are subject to a prudency review is approximately $ 1.9 billion. The 2025 ETT base rate case described below could result in a refund to customers if ETT incurs a disallowance of the transmission 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 rates, could reduce future net income and cash flows and impact financial condition.

2025 ETT Base Rate Case

In January 2025, ETT filed a request with the PUCT for a $ 57 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request is based upon a proposed 10.6 % ROE with a capital structure of 55 % debt and 45 % common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates. In April and May 2025, respectively, intervenors and PUCT staff submitted testimony challenging components of the proposed rate increase including up to $ 37 million related to increased depreciation rates and $ 32 million related to the proposed ROE and capital structure.

In June 2025, a unanimous and unopposed settlement was filed with the PUCT along with a motion to approve interim rates, equal to the rates specified in the settlement, effective on June 20, 2025. The settlement terms include a base rate increase of approximately $ 20 million, based on an ROE of 9.6 % and a capital structure of 59 % debt and 41 % equity. The settlement also includes a determination that ETT’s invested capital and rate base are prudent and properly included in rates. The motion to approve interim rates was granted in June 2025 and the settlement is subject to approval by the PUCT. If any of the costs in the case are not recoverable or revenues collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition.

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

2023 Michigan Power Supply Cost Recovery (PSCR) Reconciliation

In March 2024, I&M submitted its 2023 PSCR Reconciliation to the MPSC. In October 2024, MPSC staff and intervenors submitted testimony recommending PSCR cost disallowances associated with the OVEC Inter-Company Power Agreement (ICPA) and the Rockport UPA with AEGCo ranging from $ 3 million to $ 15 million. In July 2025, the MPSC issued an order resulting in a combined $ 3 million PSCR cost disallowance related to OVEC and Rockport UPA costs. In July 2025, the IURC issued an order on I&M’s Resource Adequacy Rider update filing approving I&M’s proposed capacity resource adjustments, including prospective recovery of OVEC capacity, energy and associated costs that were previously assigned to I&M Michigan retail customers starting with the June 2025-May 2026 PJM delivery year.

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Indiana Earnings Test

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

In January 2025, I&M submitted its FAC filing and earnings test evaluation for the period ended November 2024. I&M proposed an over-earnings credit to customers for the earnings test period ending November 2024 of $ 21 million. In April 2025, the IURC issued an order approving the $ 21 million customer credit.

KPCo Rate Matters (Applies to AEP)

Investigation of the Service, Rates and Facilities of KPCo

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

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. See “Mitchell Plant Filing for Certificate of Public Convenience and Necessity” section below for additional information.

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 (Circuit Court), challenging among other aspects of the order, the $ 14 million base rate revenue requirement reduction. In January 2025, the Circuit Court issued an order agreeing with KPCo’s appeal and remanded this issue back to the KPSC with instructions to enter an order, within 30 days, which includes setting rates to allow KPCo to recover the $ 14 million of annual PJM transmission costs effective upon KPCo's January 2024 implementation of updated base rates. In March 2025, the KPSC issued a rehearing order that approved rates for the prospective collection of test year PJM transmission costs beginning in February 2025 but denied KPCo’s request to defer and recover the historical PJM transmission costs of approximately $ 16 million incurred since January 2024. In April 2025, KPCo filed an appeal with the Circuit Court in response to the KPSC’s denial to recover PJM transmission costs incurred from January 2024 through the implementation of new rates. A Circuit Court ruling is expected in the second half of 2025.

In June 2025, KPCo issued $ 478 million of securitization bonds to recover $ 500 million of regulatory assets, including $ 311 million of plant retirement costs, $ 79 million of deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, $ 56 million of under-recovered purchased power rider costs, $ 51 million of deferred purchased power expenses and $ 3 million of issuance-related expenses, including KPSC advisor expenses. The net bond proceeds of $ 478 million also included $ 6 million for non-utility issuance costs and a $ 29 million offset for net present value of return on accumulated deferred income taxes related to KPCo’s Decommissioning Rider as ordered by the KPSC.

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Mitchell Plant Filing for Certificate of Public Convenience and Necessity

KPCo and WPCo each currently hold a 50 % ownership interest in the Mitchell Plant and related CCR investments that have been placed in service. In July 2021, the KPSC rejected KPCo’s ELG compliance plan for KPCo’s 50 % ownership share of ELG investments at the Mitchell Plant that would allow KPCo to take capacity and energy to serve customers beyond December 31, 2028. As a result of this order, WPCo holds a 100 % interest in Mitchell Plant ELG investments that have been placed in service. In addition, WPCo also holds a greater than 50 % ownership share of certain non-ELG capital investments made at Mitchell Plant which will continue to be used in the operation of Mitchell Plant beyond 2028.

In June 2025, KPCo filed a request with the KPSC for a Certificate of Public Convenience and Necessity (CPCN) to make investments necessary to reflect: (a) a 50 % share of the Mitchell Plant ELG Project and (b) a 50 % share of non-ELG capital investments. KPSC approval of these investments would allow KPCo to continue taking a 50 % share of energy and capacity from the Mitchell Plant to serve KPCo customers beyond December 31, 2028. KPCo proposed to recover the estimated $ 78 million investment in the ELG Project through KPCo’s existing Environmental Surcharge and plans to request recovery of an estimated $ 60 million of Mitchell Plant non-ELG capital investments through a future base rate filing.

As of June 30, 2025, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal and including CWIP and inventory, was $ 535 million.

If any costs related to this CPCN filing are disallowed, it could reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters (Applies to AEP and OPCo)

OVEC Cost Recovery Audits

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

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

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

Ohio Legislation (HB 15)

Ohio House Bill 15 (HB 15) was approved by the Ohio legislature in April 2025 and signed into law by the Governor of Ohio in May 2025. HB 15 is effective beginning August 14, 2025 and (a) alters rate-setting mechanisms by replacing ESPs with triennial base rate cases based on a three-year forecasted test period, effective with the end of OPCo’s previously approved ESP which ends in May 2028, (b) eliminates OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and the market revenues OPCo receives from that purchased power as of the effective date of the law and (c) repeals the statute that permits electric distribution utilities, including OPCo, to execute contracts to provide customer-sited renewable generation service such as fuel cell technology or other renewable resources prospectively.

As a result of this legislation, in the first quarter of 2025, OPCo recorded a $ 35 million estimated reduction to its OVEC-related purchased power regulatory asset for deferred net costs that are no longer probable of future recovery. Management is unable

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to predict the future impact to net income, cash flows and financial condition arising from the future changes in OPCo’s rate setting mechanisms and the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and the market revenues OPCo receives from that purchased power.

2025 Ohio Base Rate Case

In May 2025, OPCo filed a request with the PUCO for a net $ 97 million annual increase in distribution base rates based upon a 10.9 % ROE and a proposed capital structure of 49.1 % debt and 50.9 % common equity. The requested net annual increase in base rates excluded $ 308 million of existing annual rider revenue requirements (including the Distribution Investment Rider (DIR)) that OPCo proposed to be rolled into base rates upon the anticipated 2026 change in distribution base rates in this filing. The distribution base case filing also requests a revenue cap increase for the DIR and cost cap increase for OPCo’s existing Enhanced Service Reliability Rider. 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.

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 October 2024, PSO, the OCC and certain intervenors filed a joint stipulation and settlement agreement with the OCC that included a net annual revenue increase of $ 120 million based upon a 9.5 % ROE with a capital structure of 48.9 % debt and 51.1 % common equity. The agreement also allows for Rock Falls Wind Facility to be included in base rates and the deferral of certain generation-related costs necessary to comply with SPP’s 2023 increased capacity reserve margin requirements. One intervenor opposed the joint stipulation and settlement agreement. In October 2024, a hearing was held at the OCC, and PSO implemented an interim annual base rate increase of $ 120 million, subject to refund pending a final order by the OCC.

In January 2025, the OCC issued a final order approving the joint stipulation and settlement agreement without modification. In February 2025, an Oklahoma state representative filed an appeal of the final order in PSO’s base rate case. The appeal does not contest the reasonableness of the rates established under the joint stipulation and settlement agreement approved without modification in the final order, but rather raises issues related to one OCC commissioner’s participation in voting on the order and the sufficiency of an OCC audit. If the appeal is successful and the OCC modifies the final order in a future proceeding, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

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.

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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:

Jurisdiction						June 30, 2025						December 31, 2024						Approved Recovery Period						Approved Carrying Charge
						(in millions)
Arkansas						$	29.6					$	37.2					6 years						(a)
Louisiana						55.9						70.6						(b)						(b)
Texas						58.5						72.7						5 years						1.65 %
Total						$	144.0					$	180.5

(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. In August 2024, the APSC issued an order that found SWEPCo had prudently incurred these costs.

(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.

2025 Arkansas Base Rate Case

In March 2025, SWEPCo filed a request with the APSC for a $ 114 million annual base rate increase based upon a 10.9 % ROE with a capital structure of 52.3 % debt and 47.7 % common equity. The increase includes the Arkansas jurisdictional share of Diversion and Wagon Wheel wind facilities. SWEPCo is also electing to have its rates regulated under a Formula Rate Review mechanism. APSC staff and intervenor testimony is due in August 2025 and a hearing is scheduled for November 2025. 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.

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

North Central Wind Energy Facilities (NCWF)

The NCWF are subject to various regulatory performance requirements, including a Net Capacity Factor (NCF) guarantee. The NCF guarantee 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 experienced performance issues that prompted PSO and SWEPCo to file a lawsuit against the manufacturer, which led to an agreement between PSO and SWEPCo and the manufacturer that addressed the performance issues. If regulatory performance requirements, such as the NCF guarantee, are not met, PSO and SWEPCo may recognize a regulatory liability associated with a refund to retail customers. 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 (MPSC) approved a Certificate of Public Convenience and Necessity (CPCN) to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PAPUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy appealed the PAPUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. In May 2022, the Pennsylvania state court issued an order affirming the PAPUC decision as to state law claims. In December 2023, the United States District Court for the Middle District of Pennsylvania

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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, which is currently pending and awaiting decision. Additional regulatory proceedings before the PAPUC are expected to resume in 2025 or 2026. In June 2025, the MPSC gave notice that it extended a temporary extension of the construction commencement deadline until the MPSC can further consider the matter at an administrative meeting.

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 canceled and remains necessary to alleviate congestion. PJM continues to evaluate reliability and market efficiency in the area. As of June 30, 2025, AEP’s share of IEC capital expenditures was approximately $ 91 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is canceled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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

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

2021						2022						2023						2024						2025						Total
(in millions)
$	78.3					$	68.5					$	60.7					$	52.1					$	48.7					$	308.3

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

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

In June 2025, the FERC issued two orders, partially reversing its January 2024 decisions on the basis of IRS PLRs accepted into the record, and concluding that the accelerated depreciation-related NOLC adjustments should be included in rate base and should also be included in the computation of Excess ADIT regulatory liabilities to be refunded to customers. The FERC directed the AEP transmission owning subsidiaries within PJM and SPP to submit compliance filings in August 2025 that will revise March 2024 refund compliance reports and permit the collection of excess refunds provided to customers, with interest, in the annual update for the 2025 rate year.

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

						AEP						AEPTCo						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Total Revenues						$	270.5					$	214.3					$	5.6					$	10.8					$	—					$	6.4					$	26.9
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation						( 23.9 )						—						( 17.2 )						—						—						—						—
Other Operation						53.0						—						14.8						( 6.0 )						0.1						18.8						10.1
Income (Loss) Before Income Tax Expense (Benefit)						241.4						214.3						8.0						16.8						( 0.1 )						( 12.4 )						16.8
Income Tax Expense (Benefit)						( 312.8 )						( 203.2 )						( 21.4 )						( 27.8 )						—						( 15.6 )						( 38.9 )
Net Income (Loss)						554.2						417.5						29.4						44.6						( 0.1 )						3.2						55.7
Net Income Attributable to Noncontrolling Interest						55.2						55.2						—						—						—						—						—
Earnings (Loss) Attributable to Common Shareholder						$	499.0					$	362.3					$	29.4					$	44.6					$	( 0.1 )					$	3.2					$	55.7

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, or refunds of revenues collected under interim rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition.

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

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The disclosures in this note apply to all Registrants unless indicated otherwise.

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

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2024 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit (Applies to AEP)

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

AEP has $ 5 billion and $ 1 billion revolving credit facilities due in March 2029 and March 2027, respectively. 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, 2025, 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, 2025 were as follows:

Company

Amount

Maturity

(in millions)

AEP

$

360.8

July 2025 to July 2026

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, 2025, 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.

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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, 2025, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

Company						Maximum Potential Loss
						(in millions)
AEP						$	38.4
AEP Texas						8.3
APCo						5.2
I&M						3.9
OPCo						6.5
PSO						3.5
SWEPCo						4.3

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

Federal EPA’s Revised CCR Rule

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

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

AEP will seek cost recovery through regulated rates, including proposal of new regulatory mechanisms for cost recovery where existing mechanisms are not applicable. The rule could have an additional, material adverse impact on net income, cash flows and financial condition if AEP cannot ultimately recover these additional costs of compliance. Several parties, including AEP and one of its trade associations, have filed petitions for review of the Legacy CCR Rule with the U.S. Court of Appeals for the D.C. Circuit. One of the parties also filed a motion to stay the Legacy CCR Rule pending the outcome of the litigation. In November 2024, the court denied the stay motion. The litigation is being held in abeyance until August 11, 2025. The Federal EPA informed the court that it has determined it will reconsider the Legacy CCR Rule in whole or in part, but has not yet decided the full scope of reconsideration. The Federal EPA expects to have determined which aspects of the Legacy CCR Rule it will reconsider, in whole or in part, by August 11, 2025. Reconsideration of the rule will require a new round of notice-and-comment rulemaking. In July 2025, the Federal EPA issued a direct final rule and companion proposed rule that extended certain compliance deadlines for CCR management units under the Legacy CCR Rule. Management cannot predict the outcome of the litigation or any further actions by the Federal EPA related to the rule.

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

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

NUCLEAR CONTINGENCIES (Applies to AEP and I&M)

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

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

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

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

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

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

ACQUISITIONS

Green Country Power Plant, Pixley Solar Energy Facility and Flat Ridge IV Wind Energy Facility (Vertically Integrated Utilities Segment) (Applies to AEP and PSO)

In the second quarter of 2025, PSO expanded its generation portfolio by acquiring three electric generation facilities for a total of $ 1.4 billion. In May 2025, PSO acquired 100 % of the equity interests in Pixley Solar Energy, LLC, the owner of the newly constructed Pixley solar energy facility in Barber County, Kansas. The Pixley facility, placed in service in May 2025, serves both FERC and retail customers in Oklahoma. PSO’s revenue requirement is recoverable through an authorized rider until it is incorporated into base rates. Regulatory approval of Pixley’s output in retail rates included capital cost, performance and other guarantees, which may subject PSO to future regulatory liabilities. In June 2025, PSO also acquired 100 % of the equity interests in Flat Ridge IV Wind, LLC, the owner of the newly constructed Flat Ridge IV Wind Energy Facility located in Kingman and Harper Counties, Kansas. This facility, also placed in service in June 2025, serves both FERC and retail customers under similar recovery and regulatory provisions as the Pixley facility. The acquisitions of Pixley and Flat Ridge IV also resulted in the recognition of operating leases for easement and access rights to the land on which the facilities are located, as well as the associated AROs. In accordance with the guidance for “Business Combinations,” management determined the acquisitions of Pixley and Flat Ridge IV represent asset acquisitions.

Additionally, in June 2025, PSO completed the acquisition of 100 % of the equity interests in Green Country Energy, LLC, the owner of a combined-cycle natural gas facility located in Jenks, Oklahoma, following approvals from both the FERC and the OCC. The transaction included the acquisition of a previously executed capacity sales agreement between Green Country Energy, LLC, as seller, and SWEPCo, as purchaser. As a result, beginning in July 2025, PSO will sell a portion of the Green Country’s capacity to SWEPCo through May 2027, the end of the agreement’s term. The acquisition also resulted in the extinguishment of a previously executed capacity sales agreement between Green Country Energy, LLC, as seller, and PSO, as purchaser.

In accordance with the guidance for “Business Combinations,” management determined the acquisition of Green Country represents an asset acquisition. Asset acquisitions are accounted for using a cost accumulation model, with the cost of the acquisition allocated to the acquired assets and assumed liabilities based on their relative fair value. Upon closing of the transaction, PSO recognized Property, Plant and Equipment of $ 819 million, an intangible liability of $ 41 million for the fair value of the acquired SWEPCo capacity sales agreement and a regulatory liability of $ 50 million, reflective of the recognition and subsequent deferral of the gain from PSO’s extinguished capacity sales agreement. The liabilities recognized for the capacity sales agreements will reduce PSO’s revenue requirement to recover its overall investment in Green Country, which is recoverable through a rider authorized by the OCC until it is included in base rates for the depreciable life of the facility. AEP management elected the income approach for its nonrecurring valuation of both the intangible liability and regulatory liability. Specifically, management applied a discounted cash flow model based on a forward market price assumption.

The table below summarizes the impact of the acquisitions on PSO’s balance sheet as of June 30, 2025:

			Plant Name						State						Fuel Type						Generation Capacity (MWs)						Property, Plant and Equipment, Net						Operating Lease Assets												Asset Retirement Obligations						Other Liabilities
																											(in millions)
			Green Country						OK						Natural Gas						795						$	818.9					$	—											$	—					$	91.4		(a)
			Pixley						KS						Solar						189						379.6						8.9												12.4						—
			Flat Ridge IV						KS						Wind						135						305.3						7.4												3.1						—
			Total																		1,119						$	1,503.8					$	16.3											$	15.5					$	91.4

(a) $ 50 million included in Regulatory Liabilities and Deferred Investment Tax Credits, $ 21 million included in Other Current Liabilities and $ 20 million included in Deferred Credits and Other Noncurrent Liabilities on PSO’s balance sheets.

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DISPOSITIONS

Noncontrolling Interest in OHTCo and IMTCo (AEP Transmission Holdco Segment) (Applies to AEP and AEPTCo)

In January 2025, AEP announced a partnership whereby nonaffiliated entities will acquire a 19.9 % noncontrolling interest in OHTCo and IMTCo. The partnership was structured pursuant to a contribution agreement between AEPTCo, along with Midwest Transmission Holding Company LLC (“Midwest Transmission”), a wholly-owned subsidiary of AEPTCo that owns all the stock of OHTCo and IMTCo, and Olympus BidCo L.P. (“the Investor”), a special purpose entity controlled by (i) investment funds managed by or affiliated with Kohlberg Kravis Roberts & Co. L.P. and (ii) Public Sector Pension Investment Board, whereby the Investor agreed to acquire a 19.9 % noncontrolling equity interest in Midwest Transmission for $ 2.82 billion. The transaction closed in June 2025. AEP received cash proceeds of approximately $ 2.78 billion, net of transaction costs. Net proceeds will be used to help finance AEP’s $ 54 billion capital plan for 2025-2029, announced in November 2024, driven by transmission and distribution infrastructure upgrades and new generation to support anticipated load growth.

Disposition of NMRD (Generation & Marketing Segment) (Applies to AEP)

In December 2023, AEP and the joint owner signed an agreement to sell NMRD to a nonaffiliated third party and the sale was completed in February 2024. AEP received cash proceeds of approximately $ 107 million, net of taxes and transaction costs. The transaction did not have a material impact on net income or financial condition.

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

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

Components of Net Periodic Benefit Cost (Credit)

Pension Plans

Three Months Ended June 30, 2025						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Service Cost						$	23.9					$	2.2					$	2.2					$	3.1					$	2.3					$	1.6					$	1.9
Interest Cost						52.8						4.3						6.3						6.2						4.8						2.5						3.0
Expected Return on Plan Assets						( 70.2 )						( 5.5 )						( 9.4 )						( 9.7 )						( 7.4 )						( 3.8 )						( 3.6 )
Amortization of Net Actuarial Loss						4.0						0.4						0.5						0.5						0.4						0.1						0.3
Net Periodic Benefit Cost (Credit)						$	10.5					$	1.4					$	( 0.4 )					$	0.1					$	0.1					$	0.4					$	1.6

Three Months Ended June 30, 2024						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Service Cost						$	25.6					$	2.2					$	2.5					$	3.3					$	2.3					$	1.6					$	2.1
Interest Cost						51.9						4.4						6.2						5.9						4.7						2.5						3.1
Expected Return on Plan Assets						( 80.2 )						( 6.6 )						( 10.7 )						( 10.6 )						( 8.1 )						( 4.4 )						( 4.4 )
Amortization of Net Actuarial Loss						1.1						0.1						0.1						0.1						—						0.1						—
Net Periodic Benefit Cost (Credit) (a)						$	( 1.6 )					$	0.1					$	( 1.9 )					$	( 1.3 )					$	( 1.1 )					$	( 0.2 )					$	0.8

Six Months Ended June 30, 2025						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Service Cost						$	47.9					$	4.4					$	4.6					$	6.3					$	4.6					$	3.0					$	3.8
Interest Cost						105.6						8.8						12.5						12.4						9.7						5.2						6.2
Expected Return on Plan Assets						( 140.5 )						( 11.1 )						( 18.8 )						( 19.4 )						( 14.7 )						( 7.7 )						( 7.3 )
Amortization of Net Actuarial Loss						8.1						0.7						0.9						0.9						0.7						0.3						0.5
Net Periodic Benefit Cost (Credit)						$	21.1					$	2.8					$	( 0.8 )					$	0.2					$	0.3					$	0.8					$	3.2

Six Months Ended June 30, 2024						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Service Cost						$	51.2					$	4.4					$	4.9					$	6.6					$	4.7					$	3.1					$	4.0
Interest Cost						103.8						8.7						12.4						11.9						9.4						5.0						6.2
Expected Return on Plan Assets						( 160.4 )						( 13.0 )						( 21.4 )						( 21.4 )						( 16.3 )						( 8.7 )						( 8.8 )
Amortization of Net Actuarial Loss						2.2						0.2						0.2						0.2						0.1						0.1						0.1
Net Periodic Benefit Cost (Credit) (a)						$	( 3.2 )					$	0.3					$	( 3.9 )					$	( 2.7 )					$	( 2.1 )					$	( 0.5 )					$	1.5

(a) Excludes an immaterial settlement amount to a non-qualified pension plan in the second quarter of 2024 for AEP. See Note 12 - Voluntary Severance Program for additional information.

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OPEB

Three Months Ended June 30, 2025						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Service Cost						$	1.0					$	0.1					$	0.2					$	0.2					$	0.1					$	0.1					$	—
Interest Cost						8.6						0.7						1.3						0.9						0.9						0.5						0.6
Expected Return on Plan Assets						( 28.3 )						( 2.4 )						( 4.1 )						( 3.3 )						( 3.0 )						( 1.5 )						( 1.9 )
Amortization of Prior Service Credit						( 0.6 )						( 0.1 )						( 0.1 )						( 0.1 )						—						( 0.1 )						( 0.1 )
Amortization of Net Actuarial Gain						( 0.3 )						—						( 0.1 )						—						—						—						—
Net Periodic Benefit Credit						$	( 19.6 )					$	( 1.7 )					$	( 2.8 )					$	( 2.3 )					$	( 2.0 )					$	( 1.0 )					$	( 1.4 )

Three Months Ended June 30, 2024						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Service Cost						$	1.1					$	0.1					$	0.1					$	0.2					$	0.1					$	—					$	0.1
Interest Cost						10.6						0.8						1.6						1.2						1.0						0.6						0.6
Expected Return on Plan Assets						( 27.9 )						( 2.2 )						( 4.1 )						( 3.3 )						( 2.9 )						( 1.6 )						( 1.8 )
Amortization of Prior Service Credit						( 3.2 )						( 0.2 )						( 0.4 )						( 0.5 )						( 0.3 )						( 0.2 )						( 0.2 )
Amortization of Net Actuarial Loss						0.7						—						0.1						0.1						0.1						0.1						—
Net Periodic Benefit Credit (a)						$	( 18.7 )					$	( 1.5 )					$	( 2.7 )					$	( 2.3 )					$	( 2.0 )					$	( 1.1 )					$	( 1.3 )

Six Months Ended June 30, 2025						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Service Cost						$	1.8					$	0.2					$	0.3					$	0.3					$	0.2					$	0.1					$	0.1
Interest Cost						17.2						1.3						2.7						1.9						1.7						0.9						1.1
Expected Return on Plan Assets						( 56.5 )						( 4.7 )						( 8.2 )						( 6.7 )						( 5.9 )						( 3.0 )						( 3.8 )
Amortization of Prior Service Credit						( 1.2 )						( 0.1 )						( 0.2 )						( 0.2 )						( 0.1 )						( 0.1 )						( 0.1 )
Amortization of Net Actuarial Gain						( 0.6 )						—						( 0.2 )						—						—						—						—
Net Periodic Benefit Credit						$	( 39.3 )					$	( 3.3 )					$	( 5.6 )					$	( 4.7 )					$	( 4.1 )					$	( 2.1 )					$	( 2.7 )

Six Months Ended June 30, 2024						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Service Cost						$	2.2					$	0.2					$	0.2					$	0.3					$	0.2					$	0.1					$	0.2
Interest Cost						21.1						1.6						3.3						2.4						2.1						1.1						1.3
Expected Return on Plan Assets						( 55.7 )						( 4.5 )						( 8.1 )						( 6.7 )						( 5.9 )						( 3.0 )						( 3.7 )
Amortization of Prior Service Credit						( 6.4 )						( 0.5 )						( 0.9 )						( 0.9 )						( 0.6 )						( 0.4 )						( 0.5 )
Amortization of Net Actuarial Loss						1.5						0.1						0.2						0.2						0.2						0.1						0.1
Net Periodic Benefit Credit (a)						$	( 37.3 )					$	( 3.1 )					$	( 5.3 )					$	( 4.7 )					$	( 4.0 )					$	( 2.1 )					$	( 2.6 )

(a) Excludes an immaterial amount related to special termination benefits resulting from the voluntary severance program announced in the second quarter of 2024. See Note 12 - Voluntary Severance Program for additional information.

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Qualified Pension Contribution (Applies to all Registrants except AEPTCo and OPCo)

For the qualified pension plan, discretionary contributions may be made to maintain the funded status of the plan. In the second quarter of 2025, AEP made a discretionary contribution to the qualified pension plan. The following table provides details of the contribution by Registrant:

Company						Qualified Pension Plan
						(in millions)
AEP						$	94.7
AEP Texas						12.0
APCo						0.4
I&M						2.1
PSO						1.4
SWEPCo						8.8

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The disclosures in this note apply to all Registrants unless indicated otherwise.

AEP’s Reportable Segments

AEP’s primary business is the generation, transmission and distribution of electricity.  Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight applicable to each public utility subsidiary.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities

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

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

AEP Transmission Holdco

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

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

Generation & Marketing

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

• Competitive generation in PJM.

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

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

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The tables below represent AEP’s reportable segment income statement information for the three and six months ended June 30, 2025 and 2024 and reportable segment balance sheet information as of June 30, 2025 and December 31, 2024. The significant expenses disclosed below align with the segment-level information that is regularly provided to the CODM.

						Three Months Ended June 30, 2025
						VIU						T&D						AEPTHCo						G&M						Total Reportable Segments						Corporate and Other (a)						Reconciling Adjustments						Consolidated
						(in millions)
Revenues from:
External Customers						$	2,934.5					$	1,442.6					$	155.1					$	551.0					$	5,083.2					$	3.7					$	—					$	5,086.9
Other Operating Segments						80.7						7.6						601.5						15.2						705.0						25.9						( 730.9 )			(b)			—
Total Revenues						3,015.2						1,450.2						756.6						566.2						5,788.2						29.6						( 730.9 )						5,086.9
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation						920.5						203.7						—						493.4						1,617.6						—						( 76.2 )						1,541.4
Other Operation and Maintenance						981.8						541.1						45.0						( 0.3 )						1,567.6						20.5						( 659.8 )						928.3
Depreciation and Amortization						531.3						201.5						121.1						4.3						858.2						( 5.0 )						( 0.1 )						853.1
Taxes Other Than Income Taxes						122.9						159.3						77.2						0.3						359.7						0.1						5.2						365.0
Allowance for Equity Funds Used During Construction						16.0						19.6						21.5						—						57.1						—						—						57.1
Interest Expense						201.0						100.0						58.7						2.0						361.7						151.1						( 23.3 )						489.5
Income Tax Expense (Benefit)						( 136.4 )						50.9						( 139.3 )						18.2						( 206.6 )						( 44.3 )						—						( 250.9 )
Equity Earnings (Loss) of Unconsolidated Subsidiaries						0.3						0.1						22.5						—						22.9						( 2.3 )						—						20.6
Other Segment Items (c)						( 22.3 )						( 10.5 )						59.5						( 13.8 )						12.9						( 23.8 )						23.3						12.4
Earnings (Loss) Attributable to AEP Common Shareholders						$	432.7					$	223.9					$	578.4					$	62.1					$	1,297.1					$	( 71.3 )					$	—					$	1,225.8
Gross Property Additions						$	2,232.6					$	663.7					$	383.6					$	2.8					$	3,282.7					$	5.8					$	( 9.2 )					$	3,279.3

						Three Months Ended June 30, 2024
						VIU						T&D						AEPTHCo						G&M						Total Reportable Segments						Corporate and Other (a)						Reconciling Adjustments						Consolidated
						(in millions)
Revenues from:
External Customers						$	2,572.0					$	1,428.8					$	108.7					$	442.5					$	4,552.0					$	27.2					$	—					$	4,579.2
Other Operating Segments						47.0						7.1						381.2						25.0						460.3						30.5						( 490.8 )			(b)			—
Total Revenues						2,619.0						1,435.9						489.9						467.5						5,012.3						57.7						( 490.8 )						4,579.2
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation						870.8						210.5						—						364.8						1,446.1						—						( 77.6 )						1,368.5
Other Operation and Maintenance						953.2						520.7						45.7						42.4						1,562.0						24.9						( 418.1 )						1,168.8
Asset Impairments and Other Related Charges						13.4						52.9						—						76.2						142.5						—						—						142.5
Depreciation and Amortization						486.2						226.9						108.9						5.1						827.1						( 5.2 )						—						821.9
Taxes Other Than Income Taxes						132.9						178.0						77.2						0.5						388.6						0.1						4.9						393.6
Allowance for Equity Funds Used During Construction						12.8						19.8						22.6						—						55.2						—						—						55.2
Interest Expense						190.2						95.8						53.3						4.9						344.2						155.3						( 33.9 )						465.6
Income Tax Expense (Benefit)						( 53.7 )						35.4						57.0						( 6.3 )						32.4						( 25.7 )						—						6.7
Equity Earnings (Loss) of Unconsolidated Subsidiaries						0.3						( 0.7 )						26.9						—						26.5						( 1.3 )						—						25.2
Other Segment Items (c)						( 26.6 )						( 12.0 )						( 3.4 )						( 15.3 )						( 57.3 )						( 24.9 )						33.9						( 48.3 )
Earnings (Loss) Attributable to AEP Common Shareholders						$	65.7					$	146.8					$	200.7					$	( 4.8 )					$	408.4					$	( 68.1 )					$	—					$	340.3
Gross Property Additions						$	679.1					$	548.8					$	325.0					$	10.1					$	1,563.0					$	6.4					$	( 12.8 )					$	1,556.6

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						Six Months Ended June 30, 2025
						VIU						T&D						AEPTHCo						G&M						Total Reportable Segments						Corporate and Other (a)						Reconciling Adjustments						Consolidated
						(in millions)
Revenues from:
External Customers						$	6,020.0					$	2,958.1					$	271.0					$	1,281.6					$	10,530.7					$	19.6					$	—					$	10,550.3
Other Operating Segments						133.0						18.6						1,027.7						31.5						1,210.8						54.6						( 1,265.4 )			(b)			—
Total Revenues						6,153.0						2,976.7						1,298.7						1,313.1						11,741.5						74.2						( 1,265.4 )						10,550.3
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation						1,995.9						466.5						—						1,075.9						3,538.3						—						( 144.0 )						3,394.3
Other Operation and Maintenance						1,865.2						1,118.2						82.4						30.1						3,095.9						36.3						( 1,133.0 )						1,999.2
Depreciation and Amortization						1,046.5						404.4						237.3						8.4						1,696.6						( 10.1 )						—						1,686.5
Taxes Other Than Income Taxes						256.5						364.5						152.8						1.0						774.8						0.6						11.6						787.0
Allowance for Equity Funds Used During Construction						32.4						38.1						43.9						—						114.4						—						—						114.4
Interest Expense						401.7						211.6						115.6						3.9						732.8						298.1						( 46.5 )						984.4
Income Tax Expense (Benefit)						( 91.6 )						84.7						( 72.4 )						54.5						( 24.8 )						( 100.6 )						—						( 125.4 )
Equity Earnings of Unconsolidated Subsidiaries						0.6						1.4						45.7						—						47.7						11.1						—						58.8
Other Segment Items (c)						( 45.0 )						( 22.2 )						59.6						( 25.2 )						( 32.8 )						( 42.2 )						46.5						( 28.5 )
Earnings (Loss) Attributable to AEP Common Shareholders						$	756.8					$	388.5					$	813.0					$	164.5					$	2,122.8					$	( 96.8 )					$	—					$	2,026.0
Gross Property Additions						$	3,153.2					$	1,367.7					$	813.9					$	6.7					$	5,341.5					$	35.8					$	2.2					$	5,379.5

						Six Months Ended June 30, 2024
						VIU						T&D						AEPTHCo						G&M						Total Reportable Segments						Corporate and Other (a)						Reconciling Adjustments						Consolidated
						(in millions)
Revenues from:
External Customers						$	5,473.2					$	2,912.0					$	219.2					$	958.4					$	9,562.8					$	42.1					$	—					$	9,604.9
Other Operating Segments						93.7						14.1						768.0						72.6						948.4						68.4						( 1,016.8 )			(b)			—
Total Revenues						5,566.9						2,926.1						987.2						1,031.0						10,511.2						110.5						( 1,016.8 )						9,604.9
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation						1,869.9						515.8						—						737.4						3,123.1						—						( 178.8 )						2,944.3
Other Operation and Maintenance						1,838.5						1,039.9						82.8						73.9						3,035.1						61.0						( 847.5 )						2,248.6
Asset Impairments and Other Related Charges						13.4						52.9						—						76.2						142.5						—						—						142.5
Depreciation and Amortization						939.8						449.4						217.0						13.3						1,619.5						( 10.5 )						—						1,609.0
Taxes Other Than Income Taxes						272.6						368.8						152.2						0.7						794.3						0.2						9.5						804.0
Allowance for Equity Funds Used During Construction						24.5						33.9						40.4						—						98.8						—						—						98.8
Interest Expense						347.4						192.0						110.2						10.9						660.5						311.1						( 70.4 )						901.2
Income Tax Expense (Benefit)						( 259.9 )						66.9						111.3						18.8						( 62.9 )						( 72.3 )						—						( 135.2 )
Equity Earnings (Loss) of Unconsolidated Subsidiaries						0.7						( 0.8 )						49.6						0.9						50.4						( 0.7 )						—						49.7
Other Segment Items (c)						( 56.1 )						( 23.6 )						( 5.7 )						( 32.1 )						( 117.5 )						( 57.3 )						70.4						( 104.4 )
Earnings (Loss) Attributable to AEP Common Shareholders						$	626.5					$	297.1					$	409.4					$	132.8					$	1,465.8					$	( 122.4 )					$	—					$	1,343.4
Gross Property Additions						$	1,480.9					$	1,121.1					$	694.6					$	20.0					$	3,316.6					$	9.5					$	( 7.8 )					$	3,318.3

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						June 30, 2025
						VIU						T&D						AEPTHCo						G&M						Total Reportable Segments						Corporate and Other (a)						Reconciling Adjustments						Consolidated
						(in millions)
Total Assets						$	57,909.4					$	27,526.9					$	18,705.5					$	1,896.9					$	106,038.7					$	5,316.2		(d)			$	( 3,576.4 )		(e)			$	107,778.5
Investments in Equity Method Investees						$	9.0					$	3.5					$	1,036.8					$	—					$	1,049.3					$	64.9					$	—					$	1,114.2

						December 31, 2024
						VIU						T&D						AEPTHCo						G&M						Total Reportable Segments						Corporate and Other (a)						Reconciling Adjustments						Consolidated
						(in millions)
Total Assets						$	54,996.5					$	26,864.3					$	18,011.9					$	1,633.9					$	101,506.6					$	5,550.8		(d)			$	( 3,979.4 )		(e)			$	103,078.0
Investments in Equity Method Investees						$	9.1					$	2.0					$	996.1					$	—					$	1,007.2					$	48.7					$	—					$	1,055.9

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

(b) Represents intersegment revenues.

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

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

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

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

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

AEPTCo’s Reportable Segments

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

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

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The tables below present AEPTCo’s reportable segment income statement information for the three and six months ended June 30, 2025 and 2024 and reportable segment balance sheet information as of June 30, 2025 and December 31, 2024. The significant expenses disclosed below align with the segment-level information that is regularly provided to the CODM.

			Three Months Ended June 30, 2025
			State Transcos						AEPTCo Parent						Reconciling Adjustments						AEPTCo Consolidated
			(in millions)
Revenues from:
External Customers			$	144.6					$	—					$	—					$	144.6
Sales to AEP Affiliates			597.1						—						—						597.1
Other Revenues			0.1						—						—						0.1
Total Revenues			741.8						—						—						741.8
Other Operation and Maintenance			42.2						—						—						42.2
Depreciation and Amortization			118.9						—						—						118.9
Taxes Other Than Income Taxes			75.8						—						—						75.8
Interest Income			0.9						84.0						( 83.5 )			(a)			1.4
Allowance for Equity Funds Used During Construction			21.5						—						—						21.5
Interest Expense			77.5						62.6						( 83.5 )			(a)			56.6
Income Tax Expense (Benefit)			( 156.0 )						10.7						—						( 145.3 )
Other Segment Items (b)			—						60.7						—						60.7
Earnings (Loss) Attributable to AEPTCo Common Shareholders			$	605.8					$	( 50.0 )		(c)			$	—					$	555.8
Gross Property Additions			$	365.1					$	—					$	—					$	365.1

			Three Months Ended June 30, 2024
			State Transcos						AEPTCo Parent						Reconciling Adjustments						AEPTCo Consolidated
			(in millions)
Revenues from:
External Customers			$	97.0					$	—					$	—					$	97.0
Sales to AEP Affiliates			377.8						—						—						377.8
Other Revenues			0.4						—						—						0.4
Total Revenues			475.2						—						—						475.2
Other Operation and Maintenance			44.9						0.1						—						45.0
Depreciation and Amortization			106.7						—						—						106.7
Taxes Other Than Income Taxes			75.5						—						—						75.5
Interest Income			3.5						61.7						( 60.9 )			(a)			4.3
Allowance for Equity Funds Used During Construction			22.5						—						—						22.5
Interest Expense			51.4						60.9						( 60.9 )			(a)			51.4
Income Tax Expense			47.5						0.2						—						47.7
Earnings Attributable to AEPTCo Common Shareholders			$	175.2					$	0.5		(c)			$	—					$	175.7
Gross Property Additions			$	321.3					$	—					$	—					$	321.3

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			Six Months Ended June 30, 2025
			State Transcos						AEPTCo Parent						Reconciling Adjustments						AEPTCo Consolidated
			(in millions)
Revenues from:
External Customers			$	248.9					$	—					$	—					$	248.9
Sales to AEP Affiliates			1,019.9						—						—						1,019.9
Other Revenues			0.1						—						—						0.1
Total Revenues			1,268.9						—						—						1,268.9
Other Operation and Maintenance			76.4						0.2						—						76.6
Depreciation and Amortization			233.0						—						—						233.0
Taxes Other Than Income Taxes			149.9						—						—						149.9
Interest Income			1.0						173.3						( 172.5 )			(a)			1.8
Allowance for Equity Funds Used During Construction			43.9						—						—						43.9
Interest Expense			161.5						122.6						( 172.5 )			(a)			111.6
Income Tax Expense (Benefit)			( 95.2 )						10.7						—						( 84.5 )
Other Segment Items (b)			—						60.7						—						60.7
Earnings (Loss) Attributable to AEPTCo Common Shareholders			$	788.2					$	( 20.9 )		(c)			$	—					$	767.3
Gross Property Additions			$	786.9					$	—					$	—					$	786.9

			Six Months Ended June 30, 2024
			State Transcos						AEPTCo Parent						Reconciling Adjustments						AEPTCo Consolidated
			(in millions)
Revenues from:
External Customers			$	194.0					$	—					$	—					$	194.0
Sales to AEP Affiliates			761.2						—						—						761.2
Other Revenues			2.8						—						—						2.8
Total Revenues			958.0						—						—						958.0
Other Operation and Maintenance			78.6						1.6						—						80.2
Depreciation and Amortization			212.6						—						—						212.6
Taxes Other Than Income Taxes			148.9						—						—						148.9
Interest Income			4.5						118.8						( 117.1 )			(a)			6.2
Allowance for Equity Funds Used During Construction			40.4						—						—						40.4
Interest Expense			106.1						117.2						( 117.1 )			(a)			106.2
Income Tax Expense			99.8						—						—						99.8
Earnings Attributable to AEPTCo Common Shareholders			$	356.9					$	—		(c)			$	—					$	356.9
Gross Property Additions			$	657.8					$	—					$	—					$	657.8

			June 30, 2025
			State Transcos						AEPTCo Parent						Reconciling Adjustments						AEPTCo Consolidated
			(in millions)
Total Assets			$	17,080.1					$	6,241.3		(d)			$	( 6,288.6 )		(e)			$	17,032.8

			December 31, 2024
			State Transcos						AEPTCo Parent						Reconciling Adjustments						AEPTCo Consolidated
			(in millions)
Total Assets			$	16,887.7					$	8,670.4		(d)			$	( 9,187.8 )		(e)			$	16,370.3

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

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

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

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

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

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

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

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

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

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

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

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

						Notional Volume of Derivative Instruments
						June 30, 2025																																										December 31, 2024
Primary Risk Exposure						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Commodity:
Power (MWhs)						373.7						—						51.9						16.0						1.9						17.8						14.5						282.4						—						23.6						7.7						2.0						5.0						4.6
Natural Gas (MMBtus)						174.3						—						45.3						—						—						54.1						22.3						152.8						—						42.2						—						—						46.2						15.4
Heating Oil and Gasoline (Gallons)						6.6						1.9						0.8						1.2						1.0						0.6						0.8						7.9						2.0						0.9						2.0						1.1						0.7						0.9
Interest Rate (USD)						$	49.3					$	—					$	—					$	—					$	—					$	—					$	—					$	59.3					$	—					$	—					$	—					$	—					$	—					$	—
Interest Rate on Long-term Debt (USD)						$	950.0					$	—					$	—					$	—					$	—					$	—					$	—					$	950.0					$	—					$	—					$	—					$	—					$	—					$	—

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Fair Value Hedging Strategies (Applies to AEP)

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

Cash Flow Hedging Strategies

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

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

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

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

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

According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $ 95 million and $ 87 million as of June 30, 2025 and December 31, 2024, respectively. There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of June 30, 2025 and December 31, 2024. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $ 15 million and $ 3 million as of June 30, 2025 and December 31, 2024, respectively. I&M netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $ 10 million and $ 600 thousand as of June 30, 2025 and December 31, 2024, respectively. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was not material for the other Registrant Subsidiaries as of June 30, 2025 and December 31, 2024.

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

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

						June 30, 2025
						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
Assets:						(in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity						$	748.4					$	—					$	111.4					$	29.4					$	—					$	100.0					$	71.3
Hedging Contracts - Commodity						67.0						—						—						—						—						—						—
Total Current Risk Management Assets						815.4						—						111.4						29.4						—						100.0						71.3
Long-term Risk Management Assets
Risk Management Contracts - Commodity						527.6						—						2.1						3.5						—						0.1						0.4
Hedging Contracts - Commodity						79.8						—						—						—						—						—						—
Total Long-term Risk Management Assets						607.4						—						2.1						3.5						—						0.1						0.4
Total Assets						$	1,422.8					$	—					$	113.5					$	32.9					$	—					$	100.1					$	71.7
Liabilities:
Current Risk Management Liabilities
Risk Management Contracts - Commodity						$	390.3					$	0.2					$	5.2					$	27.5					$	6.0					$	8.8					$	4.2
Hedging Contracts - Commodity						20.1						—						—						—						—						—						—
Hedging Contracts - Interest Rate						26.9						—						—						—						—						—						—
Total Current Risk Management Liabilities						437.3						0.2						5.2						27.5						6.0						8.8						4.2
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity						443.8						—						1.2						4.1						41.8						2.6						0.9
Hedging Contracts - Commodity						10.8						—						—						—						—						—						—
Hedging Contracts - Interest Rate						21.0						—						—						—						—						—						—
Total Long-term Risk Management Liabilities						475.6						—						1.2						4.1						41.8						2.6						0.9
Total Liabilities						$	912.9					$	0.2					$	6.4					$	31.6					$	47.8					$	11.4					$	5.1
Total MTM Derivative Contract Net Assets (Liabilities) Recognized						$	509.9					$	( 0.2 )					$	107.1					$	1.3					$	( 47.8 )					$	88.7					$	66.6

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						December 31, 2024
						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
Assets:						(in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity						$	425.0					$	—					$	40.2					$	28.5					$	—					$	22.3					$	19.1
Hedging Contracts - Commodity						54.1						—						—						—						—						—						—
Total Current Risk Management Assets						479.1						—						40.2						28.5						—						22.3						19.1
Long-term Risk Management Assets
Risk Management Contracts - Commodity						475.4						—						2.0						1.2						—						1.6						—
Hedging Contracts - Commodity						84.6						—						—						—						—						—						—
Total Long-term Risk Management Assets						560.0						—						2.0						1.2						—						1.6						—
Total Assets						$	1,039.1					$	—					$	42.2					$	29.7					$	—					$	23.9					$	19.1
Liabilities:
Current Risk Management Liabilities
Risk Management Contracts - Commodity						$	304.1					$	0.3					$	6.6					$	10.5					$	7.5					$	7.6					$	3.4
Hedging Contracts - Commodity						11.3						—						—						—						—						—						—
Hedging Contracts - Interest Rate						36.3						—						—						—						—						—						—
Total Current Risk Management Liabilities						351.7						0.3						6.6						10.5						7.5						7.6						3.4
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity						390.7						—						0.8						2.1						40.2						0.2						—
Hedging Contracts - Commodity						2.7						—						—						—						—						—						—
Hedging Contracts - Interest Rate						35.3						—						—						—						—						—						—
Total Long-term Risk Management Liabilities						428.7						—						0.8						2.1						40.2						0.2						—
Total Liabilities						$	780.4					$	0.3					$	7.4					$	12.6					$	47.7					$	7.8					$	3.4
Total MTM Derivative Contract Net Assets (Liabilities) Recognized						$	258.7					$	( 0.3 )					$	34.8					$	17.1					$	( 47.7 )					$	16.1					$	15.7

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Offsetting Assets and Liabilities

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

						June 30, 2025
						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
Assets:						(in millions)
Current Risk Management Assets
Gross Amounts Recognized						$	815.4					$	—					$	111.4					$	29.4					$	—					$	100.0					$	71.3
Gross Amounts Offset						( 346.1 )						—						( 2.7 )						( 17.1 )						—						( 3.1 )						( 0.9 )
Net Amounts Presented						469.3						—						108.7						12.3						—						96.9						70.4
Long-term Risk Management Assets
Gross Amounts Recognized						607.4						—						2.1						3.5						—						0.1						0.4
Gross Amounts Offset						( 348.5 )						—						( 0.9 )						( 3.5 )						—						( 0.1 )						( 0.4 )
Net Amounts Presented						258.9						—						1.2						—						—						—						—
Total Assets						$	728.2					$	—					$	109.9					$	12.3					$	—					$	96.9					$	70.4
Liabilities:
Current Risk Management Liabilities
Gross Amounts Recognized						$	437.3					$	0.2					$	5.2					$	27.5					$	6.0					$	8.8					$	4.2
Gross Amounts Offset						( 331.2 )						( 0.2 )						( 3.2 )						( 26.6 )						( 0.1 )						( 3.2 )						( 0.9 )
Net Amounts Presented						106.1						—						2.0						0.9						5.9						5.6						3.3
Long-term Risk Management Liabilities
Gross Amounts Recognized						475.6						—						1.2						4.1						41.8						2.6						0.9
Gross Amounts Offset						( 284.0 )						—						( 0.9 )						( 3.8 )						—						( 0.1 )						( 0.4 )
Net Amounts Presented						191.6						—						0.3						0.3						41.8						2.5						0.5
Total Liabilities						$	297.7					$	—					$	2.3					$	1.2					$	47.7					$	8.1					$	3.8
Total MTM Derivative Contract Net Assets (Liabilities)						$	430.5					$	—					$	107.6					$	11.1					$	( 47.7 )					$	88.8					$	66.6

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						December 31, 2024
						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
Assets:						(in millions)
Current Risk Management Assets
Gross Amounts Recognized						$	479.1					$	—					$	40.2					$	28.5					$	—					$	22.3					$	19.1
Gross Amounts Offset						( 268.7 )						—						( 4.5 )						( 10.1 )						—						( 1.7 )						( 1.0 )
Net Amounts Presented						210.4						—						35.7						18.4						—						20.6						18.1
Long-term Risk Management Assets
Gross Amounts Recognized						560.0						—						2.0						1.2						—						1.6						—
Gross Amounts Offset						( 270.9 )						—						( 0.6 )						( 1.2 )						—						( 0.2 )						—
Net Amounts Presented						289.1						—						1.4						—						—						1.4						—
Total Assets						$	499.5					$	—					$	37.1					$	18.4					$	—					$	22.0					$	18.1
Liabilities:
Current Risk Management Liabilities
Gross Amounts Recognized						$	351.7					$	0.3					$	6.6					$	10.5					$	7.5					$	7.6					$	3.4
Gross Amounts Offset						( 251.7 )						( 0.3 )						( 4.6 )						( 10.2 )						( 0.2 )						( 1.8 )						( 1.1 )
Net Amounts Presented						100.0						—						2.0						0.3						7.3						5.8						2.3
Long-term Risk Management Liabilities
Gross Amounts Recognized						428.7						—						0.8						2.1						40.2						0.2						—
Gross Amounts Offset						( 204.3 )						—						( 0.6 )						( 1.7 )						—						( 0.2 )						—
Net Amounts Presented						224.4						—						0.2						0.4						40.2						—						—
Total Liabilities						$	324.4					$	—					$	2.2					$	0.7					$	47.5					$	5.8					$	2.3
Total MTM Derivative Contract Net Assets (Liabilities)						$	175.1					$	—					$	34.9					$	17.7					$	( 47.5 )					$	16.2					$	15.8

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The tables below present the Registrants’ amount of gain (loss) recognized on risk management contracts:

Amount of Gain (Loss) Recognized on Risk Management Contracts

						Three Months Ended June 30, 2025
Location of Gain (Loss)						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Vertically Integrated Utilities Revenues						$	12.3					$	—					$	—					$	—					$	—					$	—					$	—
Generation & Marketing Revenues						( 13.0 )						—						—						—						—						—						—
Electric Generation, Transmission and Distribution Revenues						—						—						0.2						12.2						—						—						—
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation						0.7						—						0.9						( 0.1 )						—						—						—
Other Operation						( 0.1 )						( 0.1 )						—						—						—						—						—
Maintenance						( 0.3 )						( 0.1 )						—						—						—						—						( 0.1 )
Regulatory Assets (a)						( 6.1 )						0.1						( 0.1 )						( 1.0 )						3.4						( 5.6 )						( 3.0 )
Regulatory Liabilities (a)						77.2						—						2.5						4.3						2.6						28.4						41.5
Total Gain (Loss) on Risk Management Contracts						$	70.7					$	( 0.1 )					$	3.5					$	15.4					$	6.0					$	22.8					$	38.4

						Three Months Ended June 30, 2024
Location of Gain (Loss)						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Vertically Integrated Utilities Revenues						$	4.3					$	—					$	—					$	—					$	—					$	—					$	—
Generation & Marketing Revenues						( 53.0 )						—						—						—						—						—						—
Electric Generation, Transmission and Distribution Revenues						—						—						—						4.3						—						—						—
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation						0.7						—						0.7						0.1						—						—						—
Other Operation						0.3						0.1						—						0.1						—						—						—
Maintenance						0.5						0.1						0.1						0.1						0.1						—						0.1
Regulatory Assets (a)						31.7						0.1						15.2						4.6						( 3.1 )						8.9						0.2
Regulatory Liabilities (a)						92.5						( 0.2 )						12.6						7.1						—						33.8						34.6
Total Gain (Loss) on Risk Management Contracts						$	77.0					$	0.1					$	28.6					$	16.3					$	( 3.0 )					$	42.7					$	34.9

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						Six Months Ended June 30, 2025
Location of Gain (Loss)						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Vertically Integrated Utilities Revenues						$	( 20.2 )					$	—					$	—					$	—					$	—					$	—					$	—
Generation & Marketing Revenues						60.2						—						—						—						—						—						—
Electric Generation, Transmission and Distribution Revenues						—						—						0.3						( 20.5 )						—						—						—
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation						3.8						—						3.8						—						—						—						—
Other Operation						( 0.2 )						( 0.1 )						—						—						—						—						—
Maintenance						( 0.4 )						( 0.1 )						—						—						—						—						( 0.1 )
Regulatory Assets (a)						( 4.5 )						0.2						—						( 1.0 )						( 0.3 )						( 1.8 )						( 1.9 )
Regulatory Liabilities (a)						230.1						—						59.5						14.8						5.8						67.0						70.7
Total Gain (Loss) on Risk Management Contracts						$	268.8					$	—					$	63.6					$	( 6.7 )					$	5.5					$	65.2					$	68.7

						Six Months Ended June 30, 2024
Location of Gain (Loss)						AEP						AEP Texas						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Vertically Integrated Utilities Revenues						$	( 21.4 )					$	—					$	—					$	—					$	—					$	—					$	—
Generation & Marketing Revenues						( 97.7 )						—						—						—						—						—						—
Electric Generation, Transmission and Distribution Revenues						—						—						0.1						( 21.5 )						—						—						—
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation						1.7						—						1.6						0.1						—						—						—
Other Operation						0.3						0.1						—						0.1						—						—						—
Maintenance						0.6						0.1						0.1						0.1						0.1						—						0.1
Regulatory Assets (a)						45.2						0.3						15.1						3.0						5.5						7.7						5.1
Regulatory Liabilities (a)						145.2						—						25.7						9.3						—						52.1						49.6
Total Gain (Loss) on Risk Management Contracts						$	73.9					$	0.5					$	42.6					$	( 8.9 )					$	5.6					$	59.8					$	54.8

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same line item on the statements of income as that of the associated risk being hedged. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

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Accounting for Fair Value Hedging Strategies (Applies to AEP)

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts net income during the period of change.

AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.

The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:

						Carrying Amount of the Hedged Liabilities												Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
						June 30, 2025						December 31, 2024						June 30, 2025						December 31, 2024
						(in millions)
Long-term Debt (a) (b)						$	( 919.1 )					$	( 898.6 )					$	29.5					$	49.3

(a) Amounts included within Noncurrent Liabilities line item Long-term Debt and Current Liabilities line item Long-term Debt Due Within One Year on the balance sheet.

(b) Amounts include $( 18 ) million and $( 22 ) million as of June 30, 2025 and December 31, 2024, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.

The pretax effects of fair value hedge accounting on income were as follows:

			Three Months Ended June 30,												Six Months Ended June 30,
			2025						2024						2025						2024
			(in millions)
Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a)			$	20.5					$	18.2					$	23.6					$	1.8
Fair Value Portion of Long-term Debt (a)			( 20.5 )						( 18.2 )						( 23.6 )						( 1.8 )

(a) Gain (Loss) is included in Interest Expense on the statements of income.

Accounting for Cash Flow Hedging Strategies (Applies to AEP, AEP Texas, APCo, I&M, PSO and SWEPCo)

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income.

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity, Fuel and Other Consumables Used for Electric Generation on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2025 and 2024, AEP applied cash flow hedging to outstanding power derivatives and the Registrant Subsidiaries did not.

The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2025, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives. During the three and six months ended June 30, 2024, AEP and AEP Texas applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not.

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.

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Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were:

						Impact of Cash Flow Hedges on the Registrants’ Balance Sheets
						June 30, 2025																								December 31, 2024
																		Portion Expected to																								Portion Expected to
						AOCI												be Reclassed to												AOCI												be Reclassed to
						Gain (Loss)												Net Income During												Gain (Loss)												Net Income During
						Net of Tax												the Next Twelve Months												Net of Tax												the Next Twelve Months
						Commodity						Interest Rate						Commodity						Interest Rate						Commodity						Interest Rate						Commodity						Interest Rate
						(in millions)
AEP						$	91.5					$	0.2					$	37.1					$	0.8					$	98.5					$	3.3					$	33.9					$	2.8
AEP Texas						—						5.9						—						0.7						—						6.3						—						0.7
APCo						—						4.7						—						0.8						—						5.1						—						0.8
I&M						—						( 4.9 )						—						( 0.4 )						—						( 5.1 )						—						( 0.4 )
PSO						—						2.4						—						0.2						—						3.6						—						0.2
SWEPCo						—						0.9						—						0.3						—						1.0						—						0.3

As of June 30, 2025, the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is approximately 10 years.

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.

Credit-Risk-Related Contingent Features

Credit Downgrade Triggers (Applies to AEP)

A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts.  The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The total exposure of AEP’s derivative contracts with collateral triggering events in a net liability position was immaterial as of June 30, 2025 and December 31, 2024. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of June 30, 2025 and December 31, 2024.

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Cross-Acceleration Triggers (Applies to AEP)

Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by the Registrants under any of their outstanding debt of at least $ 50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. AEP had derivative contracts with cross-acceleration provisions in a net liability position of $ 48 million and $ 72 million and no cash collateral posted as of June 30, 2025 and December 31, 2024, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. The Registrant Subsidiaries had no derivative contracts with cross-acceleration provisions in a net liability position as of June 30, 2025 and December 31, 2024.

Cross-Default Triggers (Applies to AEP, APCo, PSO and SWEPCo)

In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $ 50 million or greater.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. AEP had derivative contracts with cross-default provisions in a net liability position of $ 153 million and $ 164 million and no cash collateral posted as of June 30, 2025 and December 31, 2024, respectively, after considering contractual netting arrangements. If a cross-default provision would have been triggered, settlement at fair value would have been required. APCo, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $ 2 million, $ 8 million and $ 2 million, respectively, and no cash collateral posted as of June 30, 2025. APCo, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $ 1 million, $ 4 million and $ 2 million, respectively, and no cash collateral posted as of December 31, 2024. The other Registrant Subsidiaries had no derivative contracts with cross-default provisions in a net liability position as of June 30, 2025 and December 31, 2024.

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

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs.  Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market.  A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s management performs its own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.

Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities.  They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities.  Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

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Fair Value Measurements of Long-term Debt (Applies to all Registrants)

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

The book values and fair values of Long-term Debt are summarized in the following table:

						June 30, 2025												December 31, 2024
Company						Book Value						Fair Value						Book Value						Fair Value
						(in millions)
AEP						$	44,525.5					$	41,138.3					$	42,642.8					$	38,964.7
AEP Texas						6,832.3						6,303.0						6,441.6						5,831.4
AEPTCo						6,098.5						5,346.8						5,768.1						4,853.1
APCo						5,772.0						5,577.2						5,660.3						5,346.0
I&M						3,510.9						3,250.4						3,494.3						3,153.8
OPCo						3,717.1						3,138.3						3,715.7						3,203.4
PSO						3,524.0						3,310.8						2,855.6						2,562.1
SWEPCo						3,983.0						3,593.4						3,980.8						3,431.5

Fair Value Measurements of Other Temporary Investments and Restricted Cash (Applies to AEP)

Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS.

The following is a summary of Other Temporary Investments and Restricted Cash:

						June 30, 2025
												Gross						Gross
												Unrealized						Unrealized						Fair
Other Temporary Investments and Restricted Cash						Cost						Gains						Losses						Value
						(in millions)
Restricted Cash (a)						$	51.3					$	—					$	—					$	51.3
Other Cash Deposits						16.1						—						—						16.1
Fixed Income Securities – Mutual Funds (b)						159.8						—						( 3.0 )						156.8
Equity Securities – Mutual Funds						14.0						25.1						—						39.1
Total Other Temporary Investments and Restricted Cash						$	241.2					$	25.1					$	( 3.0 )					$	263.3

						December 31, 2024
												Gross						Gross
												Unrealized						Unrealized						Fair
Other Temporary Investments and Restricted Cash						Cost						Gains						Losses						Value
						(in millions)
Restricted Cash (a)						$	43.1					$	—					$	—					$	43.1
Other Cash Deposits						13.9						—						—						13.9
Fixed Income Securities – Mutual Funds (b)						167.2						—						( 5.3 )						161.9
Equity Securities – Mutual Funds						12.7						26.9						—						39.6
Total Other Temporary Investments and Restricted Cash						$	236.9					$	26.9					$	( 5.3 )					$	258.5

(a) Primarily represents amounts held for the repayment of debt.

(b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates.

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The following table provides the activity for fixed income and equity securities within Other Temporary Investments:

			Three Months Ended June 30,												Six Months Ended June 30,
			2025						2024						2025						2024
			(in millions)
Proceeds from Investment Sales			$	6.6					$	—					$	16.6					$	3.0
Purchases of Investments			5.0						1.5						6.5						3.0
Gross Realized Gains on Investment Sales			0.2						—						4.2						0.3
Gross Realized Losses on Investment Sales			0.3						—						0.5						0.2

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)

Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

• Acceptable investments (rated investment grade or above when purchased).

• Maximum percentage invested in a specific type of investment.

• Prohibition of investment in obligations of AEP, I&M or their affiliates.

• Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust funds for each regulatory jurisdiction.  Regulatory approval is required to withdraw decommissioning funds.  These funds are managed by an external investment manager that must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets.  I&M records these securities at fair value.  I&M classifies debt securities in the trust funds as available-for-sale due to their long-term purpose.

Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.

The following is a summary of nuclear trust fund investments:

			June 30, 2025																								December 31, 2024
									Gross						Gross						Other-Than-												Gross						Gross						Other-Than-
			Fair						Unrealized						Unrealized						Temporary						Fair						Unrealized						Unrealized						Temporary
			Value						Gains						Losses						Impairments						Value						Gains						Losses						Impairments
			(in millions)
Cash and Cash Equivalents			$	28.1					$	—					$	—					$	—					$	23.3					$	—					$	—					$	—
Fixed Income Securities:
United States Government			1,298.6						3.3						( 9.0 )						( 16.9 )						1,322.8						8.2						( 5.3 )						( 20.2 )
Corporate Debt			274.8						20.5						( 1.0 )						( 7.1 )						211.3						0.7						( 9.8 )						( 5.8 )
State and Local Government			—						—						—						—						—						—						—						—
Subtotal Fixed Income Securities			1,573.4						23.8						( 10.0 )						( 24.0 )						1,534.1						8.9						( 15.1 )						( 26.0 )
Equity Securities - Domestic			3,008.2						2,444.9						( 0.5 )						—						2,837.7						2,288.9						( 0.4 )						—
Spent Nuclear Fuel and Decommissioning Trusts			$	4,609.7					$	2,468.7					$	( 10.5 )					$	( 24.0 )					$	4,395.1					$	2,297.8					$	( 15.5 )					$	( 26.0 )

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The following table provides the securities activity within the decommissioning and SNF trusts:

						Three Months Ended June 30,												Six Months Ended June 30,
						2025						2024						2025						2024
						(in millions)
Proceeds from Investment Sales						$	717.9					$	584.6					$	1,294.4					$	1,154.1
Purchases of Investments						728.8						598.6						1,330.0						1,187.1
Gross Realized Gains on Investment Sales						2.4						4.9						4.3						10.3
Gross Realized Losses on Investment Sales						1.8						4.2						2.5						5.4

The base cost of fixed income securities was $ 1.6 billion and $ 1.5 billion as of June 30, 2025 and December 31, 2024, respectively.  The base cost of equity securities was $ 564 million and $ 549 million as of June 30, 2025 and December 31, 2024, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2025 was as follows:

			Fair Value of Fixed
			Income Securities
			(in millions)
Within 1 year			$	350.0
After 1 year through 5 years			635.8
After 5 years through 10 years			231.2
After 10 years			356.4
Total			$	1,573.4

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Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2025

						Level 1						Level 2						Level 3						Other						Total
Assets:						(in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash						$	48.2					$	—					$	—					$	3.1					$	51.3
Other Cash Deposits (a)						—						—						—						16.1						16.1
Fixed Income Securities – Mutual Funds						156.8						—						—						—						156.8
Equity Securities – Mutual Funds (b)						39.1						—						—						—						39.1
Total Other Temporary Investments and Restricted Cash						244.1						—						—						19.2						263.3
Risk Management Assets
Risk Management Commodity Contracts (c) (d)						2.3						758.9						499.6						( 655.5 )						605.3
Cash Flow Hedges:
Commodity Hedges (c)						—						128.0						17.5						( 22.6 )						122.9
Total Risk Management Assets						2.3						886.9						517.1						( 678.1 )						728.2
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)						15.4						—						—						12.7						28.1
Fixed Income Securities:
United States Government						—						1,298.6						—						—						1,298.6
Corporate Debt						—						274.8						—						—						274.8
Subtotal Fixed Income Securities						—						1,573.4						—						—						1,573.4
Equity Securities – Domestic (b)						3,008.2						—						—						—						3,008.2
Total Spent Nuclear Fuel and Decommissioning Trusts						3,023.6						1,573.4						—						12.7						4,609.7
Total Assets						$	3,270.0					$	2,460.3					$	517.1					$	( 646.2 )					$	5,601.2
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)						$	4.7					$	682.0					$	132.1					$	( 576.0 )					$	242.8
Cash Flow Hedges:
Commodity Hedges (c)						—						27.3						2.2						( 22.5 )						7.0
Fair Value Hedges						—						47.9						—						—						47.9
Total Risk Management Liabilities						$	4.7					$	757.2					$	134.3					$	( 598.5 )					$	297.7

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2024

						Level 1						Level 2						Level 3						Other						Total
Assets:						(in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash						$	43.1					$	—					$	—					$	—					$	43.1
Other Cash Deposits (a)						—						—						—						13.9						13.9
Fixed Income Securities – Mutual Funds						161.9						—						—						—						161.9
Equity Securities – Mutual Funds (b)						39.6						—						—						—						39.6
Total Other Temporary Investments and Restricted Cash						244.6						—						—						13.9						258.5
Risk Management Assets
Risk Management Commodity Contracts (c) (f)						2.9						597.3						291.6						( 517.2 )						374.6
Cash Flow Hedges:
Commodity Hedges (c)						—						115.6						21.9						( 12.6 )						124.9
Total Risk Management Assets						2.9						712.9						313.5						( 529.8 )						499.5
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)						9.6						—						—						13.7						23.3
Fixed Income Securities:
United States Government						—						1,322.8						—						—						1,322.8
Corporate Debt						—						211.3						—						—						211.3
State and Local Government						—						—						—						—						—
Subtotal Fixed Income Securities						—						1,534.1						—						—						1,534.1
Equity Securities – Domestic (b)						2,837.7						—						—						—						2,837.7
Total Spent Nuclear Fuel and Decommissioning Trusts						2,847.3						1,534.1						—						13.7						4,395.1
Total Assets						$	3,094.8					$	2,247.0					$	313.5					$	( 502.2 )					$	5,153.1
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)						$	4.4					$	534.1					$	147.7					$	( 433.6 )					$	252.6
Cash Flow Hedges:
Commodity Hedges (c)						—						12.6						0.2						( 12.6 )						0.2
Fair Value Hedges						—						71.6						—						—						71.6
Total Risk Management Liabilities						$	4.4					$	618.3					$	147.9					$	( 446.2 )					$	324.4

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AEP Texas

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2025

						Level 1						Level 2						Level 3						Other						Total
Assets:						(in millions)
Restricted Cash for Securitized Funding						$	13.3					$	—					$	—					$	—					$	13.3
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)						$	—					$	0.2					$	—					$	( 0.2 )					$	—

December 31, 2024

						Level 1						Level 2						Level 3						Other						Total
Assets:						(in millions)
Restricted Cash for Securitized Funding						$	23.5					$	—					$	—					$	—					$	23.5
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)						$	—					$	0.3					$	—					$	( 0.3 )					$	—

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APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2025

						Level 1						Level 2						Level 3						Other						Total
Assets:						(in millions)
Restricted Cash for Securitized Funding						$	18.2					$	—					$	—					$	—					$	18.2
Risk Management Assets
Risk Management Commodity Contracts (c)						—						4.8						108.6						( 3.5 )						109.9
Total Assets						$	18.2					$	4.8					$	108.6					$	( 3.5 )					$	128.1
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)						$	—					$	6.0					$	0.3					$	( 4.0 )					$	2.3

December 31, 2024

						Level 1						Level 2						Level 3						Other						Total
Assets:						(in millions)
Restricted Cash for Securitized Funding						$	16.2					$	—					$	—					$	—					$	16.2
Risk Management Assets
Risk Management Commodity Contracts (c)						—						6.5						35.2						( 4.6 )						37.1
Total Assets						$	16.2					$	6.5					$	35.2					$	( 4.6 )					$	53.3
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)						$	—					$	6.9					$	—					$	( 4.7 )					$	2.2

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I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2025

						Level 1						Level 2						Level 3						Other						Total
Assets:						(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)						$	—					$	17.1					$	13.0					$	( 17.8 )					$	12.3
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)						15.4						—						—						12.7						28.1
Fixed Income Securities:
United States Government						—						1,298.6						—						—						1,298.6
Corporate Debt						—						274.8						—						—						274.8
State and Local Government						—						—						—						—						—
Subtotal Fixed Income Securities						—						1,573.4						—						—						1,573.4
Equity Securities - Domestic (b)						3,008.2						—						—						—						3,008.2
Total Spent Nuclear Fuel and Decommissioning Trusts						3,023.6						1,573.4						—						12.7						4,609.7
Total Assets						$	3,023.6					$	1,590.5					$	13.0					$	( 5.1 )					$	4,622.0
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)						$	—					$	28.1					$	0.7					$	( 27.6 )					$	1.2

December 31, 2024

						Level 1						Level 2						Level 3						Other						Total
Assets:						(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)						$	—					$	19.9					$	6.9					$	( 8.4 )					$	18.4
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)						9.6						—						—						13.7						23.3
Fixed Income Securities:
United States Government						—						1,322.8						—						—						1,322.8
Corporate Debt						—						211.3						—						—						211.3
Subtotal Fixed Income Securities						—						1,534.1						—						—						1,534.1
Equity Securities - Domestic (b)						2,837.7						—						—						—						2,837.7
Total Spent Nuclear Fuel and Decommissioning Trusts						2,847.3						1,534.1						—						13.7						4,395.1
Total Assets						$	2,847.3					$	1,554.0					$	6.9					$	5.3					$	4,413.5
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)						$	—					$	9.2					$	0.5					$	( 9.0 )					$	0.7

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OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2025

						Level 1						Level 2						Level 3						Other						Total
Liabilities:						(in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c)						$	—					$	—					$	47.7					$	—					$	47.7

December 31, 2024

						Level 1						Level 2						Level 3						Other						Total
Liabilities:						(in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c)						$	—					$	0.2					$	47.5					$	( 0.2 )					$	47.5

PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2025

						Level 1						Level 2						Level 3						Other						Total
Assets:						(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)						$	—					$	3.0					$	97.0					$	( 3.1 )					$	96.9
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)						$	—					$	11.2					$	0.1					$	( 3.2 )					$	8.1

December 31, 2024

						Level 1						Level 2						Level 3						Other						Total
Assets:						(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)						$	—					$	3.1					$	20.8					$	( 1.9 )					$	22.0
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)						$	—					$	7.0					$	0.8					$	( 2.0 )					$	5.8

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SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2025

						Level 1						Level 2						Level 3						Other						Total
Assets:						(in millions)
Restricted Cash for Securitized Funding						$	16.7					$	—					$	—					$	—					$	16.7
Risk Management Assets
Risk Management Commodity Contracts (c)						—						1.0						70.7						( 1.3 )						70.4
Total Assets						$	16.7					$	1.0					$	70.7					$	( 1.3 )					$	87.1
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)						$	—					$	3.5					$	1.6					$	( 1.3 )					$	3.8

December 31, 2024

						Level 1						Level 2						Level 3						Other						Total
Assets:						(in millions)
Restricted Cash for Securitized Funding						$	3.4					$	—					$	—					$	—					$	3.4
Risk Management Assets
Risk Management Commodity Contracts (c)						—						1.0						18.1						( 1.0 )						18.1
Total Assets						$	3.4					$	1.0					$	18.1					$	( 1.0 )					$	21.5
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)						$	—					$	2.8					$	0.6					$	( 1.1 )					$	2.3

(a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third-parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.

(b) Amounts represent publicly traded equity securities and equity-based mutual funds.

(c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’

(d) The June 30, 2025 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $( 1 ) million in 2025 and $( 1 ) million in periods 2026-2028; Level 2 matures $ 5 million in 2025, $ 68 million in periods 2026-2028 and $ 4 million in periods 2029-2030; Level 3 matures $ 175 million in 2025, $ 203 million in periods 2026-2028, $ 12 million in periods 2029-2030 and $( 23 ) million in periods 2031-2034.  Risk management commodity contracts are substantially comprised of power contracts.

(e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.

(f) The December 31, 2024 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $( 1 ) million in 2025; Level 2 matures $ 16 million in 2025, $ 43 million in periods 2026-2028, $ 4 million in periods 2029-2030; Level 3 matures $ 106 million in 2025, $ 45 million in periods 2026-2028, $ 9 million in periods 2029-2030 and $( 16 ) million in periods 2031-2034.  Risk management commodity contracts are substantially comprised of power contracts.

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The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

Three Months Ended June 30, 2025						AEP						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Balance as of March 31, 2025						$	122.8					$	8.0					$	3.9					$	( 51.2 )					$	15.4					$	13.1
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)						52.7						10.1						2.9						( 0.2 )						17.6						18.6
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)						( 3.4 )						—						—						—						—						—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)						( 0.8 )						—						—						—						—						—
Settlements						( 101.2 )						( 18.1 )						( 6.9 )						2.1						( 32.9 )						( 31.7 )
Transfers into Level 3 (d) (e)						5.4						—						—						—						—						—
Transfers out of Level 3 (e)						( 2.2 )						—						—						—						—						—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)						309.5						108.3						12.4						1.6						96.8						69.1
Balance as of June 30, 2025						$	382.8					$	108.3					$	12.3					$	( 47.7 )					$	96.9					$	69.1

Three Months Ended June 30, 2024						AEP						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Balance as of March 31, 2024						$	119.1					$	4.0					$	1.0					$	( 41.0 )					$	7.7					$	5.3
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)						42.5						15.7						4.1						—						7.5						8.4
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)						4.5						—						—						—						—						—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)						0.9						—						—						—						—						—
Settlements						( 64.3 )						( 19.7 )						( 5.2 )						2.3						( 15.2 )						( 13.6 )
Transfers into Level 3 (d) (e)						2.5						—						—						—						—						—
Transfers out of Level 3 (e)						( 0.2 )						—						—						—						—						—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)						183.2						67.8						14.6						( 4.5 )						49.4						38.0
Balance as of June 30, 2024						$	288.2					$	67.8					$	14.5					$	( 43.2 )					$	49.4					$	38.1

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Six Months Ended June 30, 2025						AEP						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Balance as of December 31, 2024						$	165.6					$	35.2					$	6.4					$	( 47.5 )					$	20.0					$	17.5
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)						154.3						49.4						12.9						—						37.9						42.2
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)						16.8						—						—						—						—						—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)						5.9						—						—						—						—						—
Settlements						( 263.2 )						( 84.6 )						( 19.2 )						4.3						( 57.9 )						( 59.7 )
Transfers into Level 3 (d) (e)						( 0.3 )						—						—						—						—						—
Transfers out of Level 3 (e)						0.2						—						—						—						—						—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)						303.5						108.3						12.2						( 4.5 )						96.9						69.1
Balance as of June 30, 2025						$	382.8					$	108.3					$	12.3					$	( 47.7 )					$	96.9					$	69.1

Six Months Ended June 30, 2024						AEP						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Balance as of December 31, 2023						$	139.4					$	22.4					$	2.8					$	( 50.6 )					$	18.6					$	11.1
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)						90.8						24.1						7.3						( 0.8 )						26.2						23.6
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)						13.9						—						—						—						—						—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)						1.7						—						—						—						—						—
Settlements						( 158.3 )						( 46.5 )						( 10.0 )						4.9						( 44.8 )						( 36.0 )
Transfers into Level 3 (d) (e)						7.1						—						—						—						—						—
Transfers out of Level 3 (e)						1.9						—						—						—						—						0.5
Changes in Fair Value Allocated to Regulated Jurisdictions (f)						191.7						67.8						14.4						3.3						49.4						38.9
Balance as of June 30, 2024						$	288.2					$	67.8					$	14.5					$	( 43.2 )					$	49.4					$	38.1

(a) Included in revenues on the statements of income.

(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.

(c) Included in cash flow hedges on the statements of comprehensive income.

(d) Represents existing assets or liabilities that were previously categorized as Level 2.

(e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

(f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable.

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The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:

Significant Unobservable Inputs

June 30, 2025

																														Significant						Input/Range
						Type of						Fair Value												Valuation						Unobservable																		Weighted
Company						Input						Assets						Liabilities						Technique						Input (a)						Low						High						Average (b)
												(in millions)
AEP						Energy Contracts						$	204.2					$	129.7					Discounted Cash Flow						Forward Market Price						$	4.80					$	129.40					$	47.56
AEP						FTRs						312.9						4.6						Discounted Cash Flow						Forward Market Price						( 32.49 )						28.81						( 0.20 )
APCo						FTRs						108.6						0.3						Discounted Cash Flow						Forward Market Price						( 1.40 )						14.50						2.10
I&M						FTRs						13.0						0.7						Discounted Cash Flow						Forward Market Price						( 0.90 )						14.50						1.05
OPCo						Energy Contracts						—						47.7						Discounted Cash Flow						Forward Market Price						12.54						75.71						41.08
PSO						FTRs						97.0						0.1						Discounted Cash Flow						Forward Market Price						( 32.49 )						5.35						( 5.18 )
SWEPCo						FTRs						70.7						1.6						Discounted Cash Flow						Forward Market Price						( 32.49 )						5.35						( 5.18 )

December 31, 2024

																														Significant						Input/Range
						Type of						Fair Value												Valuation						Unobservable																		Weighted
Company						Input						Assets						Liabilities						Technique						Input (a)						Low						High						Average (b)
												(in millions)
AEP						Energy Contracts						$	221.2					$	144.6					Discounted Cash Flow						Forward Market Price						$	2.75					$	149.30					$	49.34
AEP						FTRs						92.3						3.3						Discounted Cash Flow						Forward Market Price						( 29.48 )						19.70						0.24
APCo						FTRs						35.2						—						Discounted Cash Flow						Forward Market Price						( 0.25 )						9.32						1.56
I&M						FTRs						6.9						0.5						Discounted Cash Flow						Forward Market Price						( 4.07 )						9.32						1.34
OPCo						Energy Contracts						—						47.5						Discounted Cash Flow						Forward Market Price						14.53						72.40						42.44
PSO						FTRs						20.8						0.8						Discounted Cash Flow						Forward Market Price						( 29.48 )						10.54						( 3.88 )
SWEPCo						FTRs						18.1						0.6						Discounted Cash Flow						Forward Market Price						( 29.48 )						10.54						( 3.88 )

(a) Represents market prices in dollars per MWh.

(b) The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term.

The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of June 30, 2025 and December 31, 2024:

Significant Unobservable Input

Position

Change in Input

Impact on Fair Value Measurement

Forward Market Price

Buy

Increase (Decrease)

Higher (Lower)

Forward Market Price

Sell

Increase (Decrease)

Lower (Higher)

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The disclosures in this note apply to all Registrants unless indicated otherwise.

Effective Tax Rates (ETR)

The Registrants’ interim ETR reflect the estimated annual ETR for 2025 and 2024, adjusted for tax expense associated with certain discrete items. In the second quarter of 2025, AEPTCo, APCo, I&M, PSO and SWEPCo recorded tax benefits of $ 256 million, $ 24 million, $ 38 million, $ 14 million and $ 46 million, respectively, contributing to a total AEP Consolidated benefit of $ 383 million, related to the remeasurement of Excess ADIT associated with the FERC order related to the treatment of NOLCs in transmission formula rates, driving a reduction to the interim ETR resulting in AEP’s tax rate of ( 24.2 )% for three months ended June 30, 2025 and ( 6.4 )% for six months ended June 30, 2025 as shown below.

The ETR for each of the Registrants are included in the following tables:

						Three Months Ended June 30, 2025
						AEP						AEP Texas						AEPTCo						APCo						I&M						OPCo						PSO						SWEPCo
U.S. Federal Statutory Rate						21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%
Increase (decrease) due to:
State and Local Income Taxes, Net						0.6		%				0.9		%				2.5		%				0.8		%				1.1		%				1.0		%				3.2		%				( 2.8 )		%
Tax Reform Excess ADIT Reversal						( 0.4 )		%				( 2.1 )		%				0.6		%				( 2.0 )		%				2.8		%				( 2.7 )		%				( 2.7 )		%				2.5		%
Remeasurement of Excess ADIT						( 37.0 )		%				—		%				( 54.3 )		%				( 26.0 )		%				( 40.8 )		%				—		%				( 41.4 )		%				( 79.4 )		%
Production and Investment Tax Credits						( 6.7 )		%				( 0.1 )		%				—		%				( 0.1 )		%				( 18.7 )		%				—		%				( 69.3 )		%				( 40.7 )		%
Reversal of Origination Flow-Through						—		%				0.1		%				0.2		%				( 4.1 )		%				1.8		%				0.6		%				0.3		%				0.9		%
AFUDC Equity						( 1.0 )		%				( 1.2 )		%				( 0.8 )		%				( 0.9 )		%				( 0.8 )		%				( 1.5 )		%				( 1.4 )		%				( 1.5 )		%
Flow-Through of CAMT						( 0.3 )		%				—		%				—		%				( 3.4 )		%				—		%				—		%				—		%				—		%
Other						( 0.4 )		%				0.1		%				—		%				—		%				—		%				( 0.1 )		%				0.2		%				( 0.9 )		%
Effective Income Tax Rate						( 24.2 )		%				18.7		%				( 30.8 )		%				( 14.7 )		%				( 33.6 )		%				18.3		%				( 90.1 )		%				( 100.9 )		%

						Three Months Ended June 30, 2024
						AEP						AEP Texas						AEPTCo						APCo						I&M						OPCo						PSO						SWEPCo
U.S. Federal Statutory Rate						21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%
Increase (decrease) due to:
State and Local Income Taxes, Net						0.9		%				0.5		%				2.3		%				3.0		%				( 3.7 )		%				( 1.2 )		%				( 2.9 )		%				( 0.1 )		%
Tax Reform Excess ADIT Reversal						( 6.0 )		%				( 1.2 )		%				0.2		%				( 2.9 )		%				( 15.2 )		%				( 34.9 )		%				( 3.4 )		%				2.0		%
Remeasurement of Excess ADIT						( 1.7 )		%				3.9		%				—		%				—		%				( 46.2 )		%				—		%				—		%				—		%
Production and Investment Tax Credits						( 11.0 )		%				( 0.2 )		%				—		%				( 0.1 )		%				1.8		%				—		%				( 70.6 )		%				15.9		%
Reversal of Origination Flow-Through						1.1		%				0.1		%				0.3		%				( 1.0 )		%				12.0		%				2.7		%				0.3		%				( 0.4 )		%
Other						( 2.4 )		%				( 1.3 )		%				( 2.4 )		%				( 2.1 )		%				( 2.0 )		%				( 4.1 )		%				( 1.5 )		%				0.5		%
Effective Income Tax Rate						1.9		%				22.8		%				21.4		%				17.9		%				( 32.3 )		%				( 16.5 )		%				( 57.1 )		%				38.9		%

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						Six Months Ended June 30, 2025
						AEP						AEP Texas						AEPTCo						APCo						I&M						OPCo						PSO						SWEPCo
U.S. Federal Statutory Rate						21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%
Increase (decrease) due to:
State and Local Income Taxes, Net						0.9		%				0.6		%				2.5		%				1.0		%				2.0		%				1.3		%				3.0		%				( 2.2 )		%
Tax Reform Excess ADIT Reversal						( 1.4 )		%				( 2.8 )		%				0.4		%				( 2.4 )		%				0.2		%				( 3.2 )		%				( 3.1 )		%				0.1		%
Remeasurement of Excess ADIT						( 19.5 )		%				—		%				( 34.4 )		%				( 8.1 )		%				( 24.1 )		%				—		%				( 23.5 )		%				( 45.7 )		%
Production and Investment Tax Credits						( 6.6 )		%				( 0.1 )		%				—		%				( 0.1 )		%				( 15.8 )		%				—		%				( 51.3 )		%				( 36.6 )		%
Reversal of Origination Flow-Through						0.2		%				0.1		%				0.2		%				( 1.8 )		%				1.8		%				0.7		%				0.2		%				0.8		%
AFUDC Equity						( 1.1 )		%				( 1.1 )		%				( 1.1 )		%				( 0.7 )		%				( 0.7 )		%				( 1.6 )		%				( 1.0 )		%				( 1.4 )		%
Other						0.1		%				( 0.1 )		%				—		%				0.1		%				—		%				—		%				0.1		%				( 0.2 )		%
Effective Income Tax Rate						( 6.4 )		%				17.6		%				( 11.4 )		%				9.0		%				( 15.6 )		%				18.2		%				( 54.6 )		%				( 64.2 )		%

						Six Months Ended June 30, 2024
						AEP						AEP Texas						AEPTCo						APCo						I&M						OPCo						PSO						SWEPCo
U.S. Federal Statutory Rate						21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%				21.0		%
Increase (decrease) due to:
State and Local Income Taxes, Net						1.8		%				0.4		%				2.5		%				2.6		%				2.3		%				0.6		%				—		%				( 2.4 )		%
Tax Reform Excess ADIT Reversal						( 6.0 )		%				( 1.2 )		%				0.2		%				( 10.0 )		%				( 3.4 )		%				( 10.6 )		%				( 2.8 )		%				( 1.5 )		%
Remeasurement of Excess ADIT						( 19.0 )		%				2.4		%				—		%				—		%				( 55.8 )		%				—		%				( 116.8 )		%				303.0		%
Production and Investment Tax Credits						( 7.0 )		%				( 0.2 )		%				—		%				( 0.1 )		%				( 0.5 )		%				—		%				( 61.3 )		%				69.3		%
Other						( 2.0 )		%				( 1.1 )		%				( 1.8 )		%				( 1.4 )		%				( 0.7 )		%				( 0.4 )		%				( 0.4 )		%				( 1.2 )		%
Effective Income Tax Rate						( 11.2 )		%				21.3		%				21.9		%				12.1		%				( 37.1 )		%				10.6		%				( 160.3 )		%				388.2		%

Federal and State Income Tax Audit Status

AEP is not currently under IRS audit and the statute of limitations (SOL) for the IRS to examine AEP and subsidiaries originally filed federal return has expired for tax years prior to 2021. In July 2025, AEP received notification that its 2023 federal income tax return was selected for IRS examination.

AEP and subsidiaries file income tax returns in various state and local jurisdictions. AEP and subsidiaries are not currently under any state and local income tax examinations. Generally, the SOL have expired for tax years prior to 2021. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

Federal Legislation

On July 4, 2025, President Trump signed H.R. 1 into law, commonly known as the One Big Beautiful Bill Act (OBBBA). Most notably for AEP, this budget reconciliation legislation modifies and accelerates the phase out of wind and solar PTCs and ITCs, adds new restrictions to guard against certain foreign ownership or influence with respect to otherwise credit-eligible projects and makes 100% bonus depreciation permanent for our non-regulated entities. With the exception of bonus depreciation, this legislation is prospective and has no material impact on the current period financial statements. Following enactment of the legislation, on July 7, 2025, the President issued an Executive Order directing the Department of Treasury to issue new and revised wind and solar tax credit guidance within 45 days, which could impose further practical limits on the development of wind and solar projects. In addition to this potential near term guidance, additional significant guidance from the Department of Treasury and the IRS is expected on the tax provisions included in the OBBBA. AEP will continue to monitor any issued guidance and evaluate the impact on future net income, cash flows and financial condition.

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In April 2024, management announced a voluntary severance program designed to achieve a reduction in the size of AEP’s workforce. Approximately 7,400 of AEP’s 16,800 employees were eligible to participate in the program. Approximately 1,000 employees chose to take the voluntary severance package and substantially all terminated employment in July 2024. The severance program provides two weeks of base pay for every year of service with a minimum of four weeks and a maximum of 52 weeks of base pay. Certain positions impacted by the voluntary severance program have been and will continue to be refilled to maintain safe, effective and efficient operations. Net savings from the program will help offset increasing operating expenses and high interest costs in order to keep electricity costs affordable for customers.

AEP recorded a charge to expense in the second quarter of 2024 related to this voluntary severance program.

						AEP						AEP Texas						AEPTCo						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Severance Expense Incurred						$	122.0					$	19.8					$	10.7					$	26.5					$	14.8					$	14.8					$	10.1					$	16.9

These expenses were primarily included in Other Operation and Maintenance on the statements of income and Other Current Liabilities on the balance sheets. Settlement accounting was triggered for the qualified pension plan in November 2024 under the accounting guidance for “Compensation - Retirement Benefits” and a settlement charge of $ 90 million was recorded. As of June 30, 2025, all incurred expenses have been settled. AEP will seek recovery for the portion of the expense related to regulated operations. See Note 7 - Benefit Plans for additional information associated with the plan.

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The disclosures in this note apply to all Registrants, unless indicated otherwise.

Common Stock (Applies to AEP)

At-the-Market (ATM) Program

In 2024, approximately $ 0.4 billion of common stock was offered and sold under the ATM program. There were no issuances under the ATM program for the six months ended June 30, 2025. Approximately $ 1.3 billion of equity is available for issuance under the ATM program upon the filing of a prospectus supplement.

Forward Sale of Equity

In March 2025, AEP entered into separate forward sale agreements with nonaffiliated forward purchasers relating to 22,549,020 shares of AEP’s common stock at an initial price of $ 102.00 per share, exclusive of an underwriting discount equal to $ 2.244 per share. Except in certain specified circumstances that would require physical share settlement, AEP may elect to settle the forward sale transaction by means of physical, cash or net share settlement. The timing of the settlement of the forward sale agreements is also at AEP’s discretion and management currently expects settlement to occur on or prior to December 31, 2026. To the extent the forward sale agreements are physically settled, AEP will issue common stock to the forward purchasers and receive cash proceeds based on the applicable forward sale price on the settlement date as defined in the forward sale agreements. As of June 30, 2025, AEP expects approximately $ 2.25 billion of net cash proceeds from the full physical settlement of the forward sale agreements and management anticipates using any future proceeds for general corporate purposes, which may include capital contributions to utility subsidiaries, acquisitions or repayment of debt. The forward sale transactions will be classified as equity transactions because they are indexed to AEP’s common stock and physical settlement is within AEP’s control.

Long-term Debt Outstanding (Applies to AEP)

The following table details long-term debt outstanding, net of issuance costs and premiums or discounts:

Type of Debt						June 30, 2025						December 31, 2024
						(in millions)
Senior Unsecured Notes						$	37,019.1					$	36,410.9
Pollution Control Bonds						1,730.3						1,771.3
Notes Payable						644.5						609.9
Securitization Bonds						1,021.0						578.0
Spent Nuclear Fuel Obligation (a)						323.2						316.3
Junior Subordinated Notes						2,581.2						2,579.1
Other Long-term Debt						1,206.2						377.3
Total Long-term Debt Outstanding						44,525.5						42,642.8
Long-term Debt Due Within One Year						3,212.4						3,335.0
Long-term Debt						$	41,313.1					$	39,307.8

(a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $ 375 million and $ 367 million as of June 30, 2025 and December 31, 2024, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.

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Long-term Debt Activity

Long-term debt and other securities issued, retired and principal payments made during the first six months of 2025 are shown in the following tables:

												Principal						Interest
Company						Type of Debt						Amount (a)						Rate						Due Date
Issuances:												(in millions)						(%)
AEP Texas						Other Long-term Debt						$	400.0					Variable						2026
AEPTCo						Senior Unsecured Notes						425.0						5.38						2035
APCo						Other Long-term Debt						425.0						Variable						2026
APCo						Pollution Control Bonds						104.4						3.70						2028
I&M						Notes Payable						100.0						4.89						2029
I&M						Pollution Control Bonds						150.0						3.70						2029
PSO						Senior Unsecured Notes						800.0						5.45						2036
Non-Registrant:
KPCo						Other Long-term Debt						150.0						Variable						2026
KPCo						Securitization Bonds						477.7						5.30						2045
Transource Energy						Other Long-term Debt						29.5						Variable						2025
WPCo						Other Long-term Debt						125.0						Variable						2026
Total Issuances												$	3,186.6

(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

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												Principal						Interest
Company						Type of Debt						Amount Paid						Rate						Due Date
Retirements and Principal Payments:												(in millions)						(%)
AEP Texas						Securitization Bonds						$	10.3					2.06						2025
AEP Texas						Securitization Bonds						1.9						2.29						2029
AEPTCo						Senior Unsecured Notes						50.0						3.66						2025
AEPTCo						Senior Unsecured Notes						40.0						3.76						2025
APCo						Other Long-term Debt						0.1						13.72						2026
APCo						Pollution Control Bonds						104.4						3.75						2025
APCo						Securitization Bonds						13.9						3.77						2028
APCo						Senior Unsecured Notes						300.0						3.40						2025
I&M						Notes Payable						1.1						Variable						2025
I&M						Notes Payable						2.6						0.93						2025
I&M						Notes Payable						7.5						3.44						2026
I&M						Notes Payable						8.7						5.93						2027
I&M						Notes Payable						10.1						6.01						2028
I&M						Notes Payable						16.3						6.41						2028
I&M						Notes Payable						3.5						4.89						2029
I&M						Other Long-term Debt						0.2						6.00						2025
I&M						Pollution Control Bonds						40.0						0.75						2025
I&M						Pollution Control Bonds						50.0						2.75						2025
I&M						Pollution Control Bonds						100.0						3.05						2025
PSO						Other Long-term Debt						0.3						3.00						2027
PSO						Senior Unsecured Notes						125.0						3.17						2025
Non-Registrant:
KPCo						Other Long-term Debt						150.0						Variable						2025
KPCo						Other Long-term Debt						150.0						Variable						2026
Transource Energy						Senior Unsecured Notes						1.2						2.75						2050
WPCo						Senior Unsecured Notes						122.0						3.70						2025
WPCo						Notes Payable						15.0						6.89						2034
Total Retirements and Principal Payments												$	1,324.1

Financing Activities Subsequent Events

In July 2025, AEGCo retired $ 45 million of Pollution Control Bonds.

In July 2025, I&M retired $ 10 million of Notes Payable related to DCC Fuel.

In July 2025, Transource Energy issued $ 4 million of variable rate Other Long-term Debt due in 2028.

In July 2025, AEP made a capital contribution of $ 200 million to AEP Texas.

Debt Covenants (Applies to AEP and AEPTCo)

Covenants in AEPTCo’s note purchase agreements and indenture limit the amount of contractually-defined priority debt (which includes a further sub-limit of $ 50 million of secured debt) to 10 % of consolidated tangible net assets. AEPTCo’s contractually-defined priority debt was 0.3 % of consolidated tangible net assets as of June 30, 2025. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreements.

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Dividend Restrictions

Utility Subsidiaries’ Restrictions

Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends.

All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act requirement that prohibits the payment of dividends out of capital accounts in certain circumstances; payment of dividends is generally allowed out of retained earnings. The Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to APCo and I&M.

Certain AEP subsidiaries have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5 %. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.

The Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings.

Parent Restrictions (Applies to AEP)

The holders of AEP’s common stock are entitled to receive the dividends declared by the AEP Board provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.

Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5 %. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.

Corporate Borrowing Program (Applies to all Registrant Subsidiaries)

AEP subsidiaries use a corporate borrowing program to meet their short-term borrowing needs. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP. The AEP Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of June 30, 2025 and December 31, 2024 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits for the six months ended June 30, 2025 are described in the following table:

						Maximum												Average												Net Loans to
						Borrowings						Maximum						Borrowings						Average						(Borrowings from)						Authorized
						from the						Loans to the						from the						Loans to the						the Utility Money						Short-term
						Utility						Utility						Utility						Utility						Pool as of						Borrowing
Company						Money Pool						Money Pool						Money Pool						Money Pool						June 30, 2025						Limit
						(in millions)
AEP Texas						$	468.4					$	112.8					$	182.7					$	62.5					$	( 109.5 )					$	600.0
AEPTCo						403.6						312.2						192.0						39.8						32.7						820.0			(a)
APCo						263.5						242.1						141.3						30.0						( 154.8 )						750.0
I&M						145.2						19.3						77.2						6.1						( 25.7 )						500.0
OPCo						270.9						165.9						71.6						81.7						( 203.0 )						600.0
PSO						505.1						391.5						204.1						167.0						( 319.7 )						750.0
SWEPCo						471.9						76.3						285.9						10.2						76.3						750.0

(a)    Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.

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The activity in the above table does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of June 30, 2025 and December 31, 2024 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the six months ended June 30, 2025 is described in the following table:

						Maximum Loans						Average Loans						Loans to the Nonutility
						to the Nonutility						to the Nonutility						Money Pool as of
Company						Money Pool						Money Pool						June 30, 2025
			(in millions)
AEP Texas						$	7.2					$	7.1					$	7.1
SWEPCo						2.4						2.3						2.4

AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of borrowings from AEP as of June 30, 2025 and December 31, 2024 are included in Advances from Affiliates on AEPTCo’s balance sheets. AEPTCo’s direct financing activities with AEP and corresponding authorized borrowing limit for the six months ended June 30, 2025 are described in the following table:

																														Borrowings												Authorized
						Maximum						Maximum						Average						Average						from AEP						Loans to						Short-term
						Borrowings						Loans						Borrowings						Loans						as of						AEP as of						Borrowing
Company						from AEP						to AEP						from AEP						to AEP						June 30, 2025						June 30, 2025						Limit (a)
						(in millions)
AEPTCo Parent						$	106.6					$	132.6					$	13.6					$	38.2					$	10.5					$	—					$	—
SWTCo						2.0						—						1.9						—						2.0						—						50.0
Midwest Transmission Holdings						—						32.6						—						11.0						—						—						—

(a)    Amount represents the authorized short-term borrowing limit from FERC or state regulatory agencies not otherwise included in the utility money pool above.

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:

						Six Months Ended June 30,
						2025						2024
Maximum Interest Rate						4.83		%				5.79		%
Minimum Interest Rate						4.14		%				5.14		%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized in the following table:

						Average Interest Rate for Funds												Average Interest Rate for Funds
						Borrowed from the Utility Money Pool												Loaned to the Utility Money Pool
						for Six Months Ended June 30,												for Six Months Ended June 30,
Company						2025						2024						2025						2024
AEP Texas						4.69		%				5.70		%				4.72		%				5.49		%
AEPTCo						4.68		%				5.71		%				4.62		%				5.62		%
APCo						4.69		%				5.73		%				4.58		%				5.64		%
I&M						4.69		%				5.67		%				4.64		%				5.68		%
OPCo						4.65		%				5.70		%				4.70		%				5.52		%
PSO						4.67		%				5.64		%				4.68		%				—		%
SWEPCo						4.69		%				5.64		%				4.65		%				—		%

---

Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:

Six Months Ended June 30, 2025

Six Months Ended June 30, 2024

Maximum

Minimum

Average

Maximum

Minimum

Average

Interest Rate

Interest Rate

Interest Rate

Interest Rate

Interest Rate

Interest Rate

for Funds

for Funds

for Funds

for Funds

for Funds

for Funds

Loaned to

Loaned to

Loaned to

Loaned to

Loaned to

Loaned to

the Nonutility

the Nonutility

the Nonutility

the Nonutility

the Nonutility

the Nonutility

Company

Money Pool

Money Pool

Money Pool

Money Pool

Money Pool

Money Pool

AEP Texas

4.76

%

4.64

%

4.70

%

5.79

%

5.56

%

5.69

%

SWEPCo

4.76

%

4.64

%

4.70

%

5.79

%

5.56

%

5.68

%

AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:

						Maximum						Minimum						Maximum						Minimum						Average						Average
						Interest Rate						Interest Rate						Interest Rate						Interest Rate						Interest Rate						Interest Rate
Six Months						for Funds						for Funds						for Funds						for Funds						for Funds						for Funds
Ended						Borrowed						Borrowed						Loaned						Loaned						Borrowed						Loaned
June 30,						from AEP						from AEP						to AEP						to AEP						from AEP						to AEP
2025						4.76		%				4.63		%				4.76		%				4.63		%				4.69		%				4.69		%
2024						5.79		%				5.55		%				5.79		%				5.55		%				5.68		%				5.68		%

Short-term Debt (Applies to AEP and SWEPCo)

Outstanding short-term debt was as follows:

												June 30, 2025												December 31, 2024
												Outstanding						Interest						Outstanding						Interest
Company						Type of Debt						Amount						Rate (a)						Amount						Rate (a)
												(dollars in millions)
AEP						Securitized Debt for Receivables (b)						$	900.0					4.57		%				$	900.0					4.73		%
AEP						Commercial Paper						600.0						4.62		%				1,618.3						4.70		%
SWEPCo						Notes Payable						1.6						6.68		%				5.5						6.69		%
						Total Short-term Debt						$	1,501.6											$	2,523.8

(a) Weighted-average rate as of June 30, 2025 and December 31, 2024, respectively.

(b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.

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Securitized Accounts Receivables – AEP Credit (Applies to AEP)

AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.

AEP Credit’s receivables securitization agreement provides a commitment of $ 900 million from bank conduits to purchase receivables and expires in September 2026. As of June 30, 2025, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

Accounts receivable information for AEP Credit was as follows:

						Three Months Ended June 30,												Six Months Ended June 30,
						2025						2024						2025						2024
						(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable						4.53		%				5.51		%				4.57		%				5.56		%
Net Uncollectible Accounts Receivable Written-Off						$	6.1					$	5.8					$	13.9					$	13.9

						June 30, 2025						December 31, 2024
						(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts						$	1,233.9					$	1,117.0
Short-term – Securitized Debt of Receivables						900.0						900.0
Delinquent Securitized Accounts Receivable						58.5						56.2
Bad Debt Reserves Related to Securitization						45.1						44.5
Unbilled Receivables Related to Securitization						390.6						335.5

AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.

Securitized Accounts Receivables – AEP Credit (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo)

Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were:

Company						June 30, 2025						December 31, 2024
						(in millions)
APCo						$	197.4					$	192.7
I&M						182.9						160.5
OPCo						477.4						470.7
PSO						158.1						111.4
SWEPCo						189.7						153.5

---

The fees paid to AEP Credit for customer accounts receivable sold were:

						Three Months Ended June 30,												Six Months Ended June 30,
Company						2025						2024						2025						2024
						(in millions)
APCo						$	3.3					$	3.9					$	7.2					$	8.1
I&M						3.5						3.8						7.0						7.9
OPCo						7.5						7.4						14.9						14.8
PSO						2.8						3.4						5.7						6.8
SWEPCo						3.7						4.3						7.8						9.1

The proceeds on the sale of receivables to AEP Credit were:

						Three Months Ended June 30,												Six Months Ended June 30,
Company						2025						2024						2025						2024
						(in millions)
APCo						$	429.8					$	447.3					$	1,034.6					$	983.3
I&M						545.4						502.1						1,130.2						1,031.8
OPCo						735.2						771.5						1,595.5						1,617.2
PSO						431.9						425.0						806.7						786.6
SWEPCo						456.0						471.9						884.1						897.3

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

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE.  A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.

AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. AEP has not provided material financial or other support that was not previously contractually required to any of its consolidated VIEs. AEP’s interests in non-consolidated VIEs are accounted for under the equity method of accounting.

Consolidated Variable Interest Entities

Cost Recovery Funding (Applies to AEP)

In June 2025, Cost Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to plant retirement costs, deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, deferred purchased power expenses, under-recovered purchased power rider costs and issuance-related expenses, including KPSC advisor expenses. Management concluded that KPCo is the primary beneficiary of Cost Recovery Funding because KPCo has the power to direct the most significant activities of the VIE and KPCo’s equity interest could potentially be significant. Therefore, KPCo is required to consolidate Cost Recovery Funding. As of June 30, 2025, $ 9 million of the securitized bonds was included in Long-term Debt Due Within One Year and $ 459 million was included in Long-term Debt on the balance sheet. Cost Recovery Funding’s securitized assets were $ 468 million as of June 30, 2025, which was presented separately on the face of the balance sheet.

The securitized assets represent the right to impose and collect KPCo recovery charges from KPCo’s customers. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to KPCo or any other AEP entity. KPCo acts as the servicer for Cost Recovery Funding’s securitized assets and remits all related amounts collected from customers to Cost Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Cost Recovery Funding’s assets and liabilities on the balance sheet.

The 2024 Annual Report includes a detailed discussion of other Registrants’ consolidated VIEs.

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The balances below represent the assets and liabilities of AEP’s consolidated VIEs. These balances include intercompany transactions that are eliminated upon consolidation.

			June 30, 2025
			Consolidated VIEs
			SWEPCo Sabine						I&M DCC Fuel												AEP Texas Restoration Funding						APCo Appalachian Consumer Rate Relief Funding						SWEPCo Storm Recovery Funding						KPCo Cost Recovery Funding						AEP Credit						Protected Cell of EIS						Transource Energy
			(in millions)
ASSETS
Current Assets			$	3.1					$	95.0											$	18.6					$	16.0					$	18.1					$	3.1					$	1,235.0					$	209.9					$	58.6
Net Property, Plant and Equipment			—						181.1												—						—						—						—						—						—						621.8
Other Noncurrent Assets			97.1						98.1												110.6			(a)			93.7			(b)			324.7						469.4			(c)			10.7						—						7.9
Total Assets			$	100.2					$	374.2											$	129.2					$	109.7					$	342.8					$	472.5					$	1,245.7					$	209.9					$	688.3
LIABILITIES AND EQUITY
Current Liabilities			$	16.6					$	94.8											$	30.7					$	30.8					$	28.5					$	10.7					$	1,179.5					$	46.6					$	30.1
Noncurrent Liabilities			83.4						279.4												97.2						77.0						312.6						459.4						1.0						105.6						333.1
Equity			0.2						—												1.3						1.9						1.7						2.4						65.2						57.7						325.1
Total Liabilities and Equity			$	100.2					$	374.2											$	129.2					$	109.7					$	342.8					$	472.5					$	1,245.7					$	209.9					$	688.3

(a) Includes an intercompany item eliminated in consolidation of $ 5 million.

(b) Includes an intercompany item eliminated in consolidation of $ 1 million .

(c) Includes an intercompany item eliminated in consolidation of $ 16 million.

			December 31, 2024
			Consolidated VIEs
			SWEPCo Sabine						I&M DCC Fuel												AEP Texas Restoration Funding						APCo Appalachian Consumer Rate Relief Funding						SWEPCo Storm Recovery Funding						AEP Credit						Protected Cell of EIS						Transource Energy
			(in millions)
ASSETS
Current Assets			$	6.0					$	79.3											$	21.3					$	14.2					$	3.4					$	1,118.3					$	218.5					$	40.2
Net Property, Plant and Equipment			—						132.3												—						—						—						—						—						598.3
Other Noncurrent Assets			110.8						63.6												121.9			(a)			109.6			(b)			331.4						10.5						—						3.5
Total Assets			$	116.8					$	275.2											$	143.2					$	123.8					$	334.8					$	1,128.8					$	218.5					$	642.0
LIABILITIES AND EQUITY
Current Liabilities			$	20.1					$	79.2											$	30.7					$	30.5					$	24.4					$	1,068.8					$	54.7					$	57.2
Noncurrent Liabilities			96.3						196.0												111.2						91.4						308.7						1.0						96.0						274.3
Equity			0.4						—												1.3						1.9						1.7						59.0						67.8						310.5
Total Liabilities and Equity			$	116.8					$	275.2											$	143.2					$	123.8					$	334.8					$	1,128.8					$	218.5					$	642.0

(a) Includes an intercompany item eliminated in consolidation of $ 5 million .

(b) Includes an intercompany item eliminated in consolidation of $ 1 million .

Significant Variable Interests in Non-Consolidated VIEs and Significant Equity Method Investments

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The disclosures in this note apply to AEP, PSO and SWEPCo.

Asset Retirement Obligations

The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal mining facilities. AEP records ARO for the decommissioning of the Cook Plant. The table below summarizes significant changes to the Registrants ARO recorded in 2025 and should be read in conjunction with the Property, Plant and Equipment note within the 2024 Annual Report.

The following is a reconciliation of the aggregate carrying amounts of ARO for AEP, PSO and SWEPCo:

Company						ARO as of December 31, 2024						Accretion Expense						Liabilities Incurred						Liabilities Settled						Revisions in Cash Flow Estimates (a)						ARO as of June 30, 2025
						(in millions)
AEP (b)(c)(d)(e)(f)(g)						$	3,611.7					$	84.6					$	17.4					$	( 42.4 )					$	34.8					$	3,706.1
PSO (b)(e)(f)(g)						121.8						3.6						15.5						( 1.3 )						( 2.8 )						136.8
SWEPCo (b)(d)(e)(f)						278.7						8.7						—						( 27.5 )						31.6						291.5

(a) Unless discussed above, primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs.

(b) Includes ARO related to ash disposal facilities.

(c) Includes ARO related to nuclear decommissioning costs for the Cook Plant.

(d) Includes ARO related to Sabine and DHLC.

(e) Includes ARO related to asbestos removal.

(f) Includes ARO related to renewables.

(g) Includes ARO related to incurred ARO liabilities due to the acquisitions of Pixley Solar Energy Facility and Flat Ridge IV Wind Energy Facility. See the “Acquisitions” section of Note 6 for additional information.

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The disclosures in this note apply to all Registrants, unless indicated otherwise.

Disaggregated Revenues from Contracts with Customers

The tables below represent AEP’s reportable segment and Registrant Subsidiary revenues from contracts with customers, net of respective provisions for refund, by type of revenue:

						Three Months Ended June 30, 2025
						VIU						T&D						AEPTHCo						G&M						Corporate and Other						Reconciling Adjustments						AEP Consolidated
						(in millions)
Retail Revenues:
Residential Revenues						$	1,029.7					$	611.8					$	—					$	—					$	—					$	—					$	1,641.5
Commercial Revenues						749.5						420.6						—						—						—						—						1,170.1
Industrial Revenues (a)						704.6						145.1						—						—						—						( 0.3 )						849.4
Other Retail Revenues						60.5						14.1						—						—						—						—						74.6
Total Retail Revenues						2,544.3						1,191.6						—						—						—						( 0.3 )						3,735.6
Wholesale and Competitive Retail Revenues:
Generation Revenues						237.3						—						—						38.3						—						—						275.6
Transmission Revenues (b)						157.2						197.4						698.3						—						—						( 622.1 )						430.8
Retail, Trading and Marketing Revenues (c)						—						—						—						538.6						—						( 15.3 )						523.3
Total Wholesale and Competitive Retail Revenues						394.5						197.4						698.3						576.9						—						( 637.4 )						1,229.7
Other Revenues from Contracts with Customers (d)						49.4						46.2						8.9						2.4						27.4						( 44.2 )						90.1
Total Revenues from Contracts with Customers						2,988.2						1,435.2						707.2						579.3						27.4						( 681.9 )						5,055.4
Other Revenues:
Alternative Revenue Programs (a) (e)						14.5						12.4						49.5						—						—						( 47.0 )						29.4
Other Revenues (a) (f)						12.5						2.6						( 0.1 )						( 13.1 )						2.2						( 2.0 )						2.1
Total Other Revenues						27.0						15.0						49.4						( 13.1 )						2.2						( 49.0 )						31.5
Total Revenues						$	3,015.2					$	1,450.2					$	756.6					$	566.2					$	29.6					$	( 730.9 )					$	5,086.9

(a) Amounts include affiliated and nonaffiliated revenues.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $ 558 million. The affiliated revenues for Vertically Integrated Utilities were $ 65 million. The remaining affiliated amounts were immaterial.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $ 16 million. The remaining affiliated amounts were immaterial.

(d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $ 26 million. The remaining affiliated amounts were immaterial.

(e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

(f) Generation & Marketing includes economic hedge activity.

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						Three Months Ended June 30, 2024
						VIU						T&D						AEPTHCo						G&M						Corporate and Other						Reconciling Adjustments						AEP Consolidated
						(in millions)
Retail Revenues:
Residential Revenues						$	949.0					$	650.2					$	—					$	—					$	—					$	—					$	1,599.2
Commercial Revenues						649.8						391.1						—						—						—						—						1,040.9
Industrial Revenues (a)						652.8						123.0						—						—						—						( 0.1 )						775.7
Other Retail Revenues						55.8						13.7						—						—						—						—						69.5
Total Retail Revenues						2,307.4						1,178.0						—						—						—						( 0.1 )						3,485.3
Wholesale and Competitive Retail Revenues:
Generation Revenues						149.0						—						—						23.7						—						( 0.1 )						172.6
Transmission Revenues (b)						123.0						208.3						496.6						—						—						( 397.0 )						430.9
Renewable Generation Revenues (a)						—						—						—						8.2						—						( 1.4 )						6.8
Retail, Trading and Marketing Revenues (c)						—						—						—						485.5						0.3						( 23.7 )						462.1
Total Wholesale and Competitive Retail Revenues						272.0						208.3						496.6						517.4						0.3						( 422.2 )						1,072.4
Other Revenues from Contracts with Customers (d)						47.4						38.9						6.2						1.0						55.2						( 48.8 )						99.9
Total Revenues from Contracts with Customers						2,626.8						1,425.2						502.8						518.4						55.5						( 471.1 )						4,657.6
Other Revenues:
Alternative Revenue Programs (a) (e)						( 12.1 )						6.7						( 12.9 )						—						—						( 17.3 )						( 35.6 )
Other Revenues (a) (f)						4.3						4.0						—						( 50.9 )						2.2						( 2.4 )						( 42.8 )
Total Other Revenues						( 7.8 )						10.7						( 12.9 )						( 50.9 )						2.2						( 19.7 )						( 78.4 )
Total Revenues						$	2,619.0					$	1,435.9					$	489.9					$	467.5					$	57.7					$	( 490.8 )					$	4,579.2

(a) Amounts include affiliated and nonaffiliated revenues.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $ 393 million. The affiliated revenues for Vertically Integrated Utilities were $ 41 million. The remaining affiliated amounts were immaterial.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $ 24 million. The remaining affiliated amounts were immaterial.

(d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $ 30 million. The remaining affiliated amounts were immaterial.

(e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

(f) Generation & Marketing includes economic hedge activity.

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						Three Months Ended June 30, 2025
						AEP Texas						AEPTCo						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Retail Revenues:
Residential Revenues						$	180.2					$	—					$	365.2					$	190.1					$	431.5					$	190.4					$	191.3
Commercial Revenues						114.6						—						194.0						192.2						306.2						135.2						155.4
Industrial Revenues (a)						41.7						—						210.5						156.7						103.5						91.3						103.2
Other Retail Revenues						10.1						—						28.2						1.3						4.1						26.4						2.7
Total Retail Revenues						346.6						—						797.9						540.3						845.3						443.3						452.6
Wholesale Revenues:
Generation Revenues (b)						—						—						77.9						138.2						—						1.5						48.6
Transmission Revenues (c)						175.4						682.3						45.9						18.6						22.0						16.0						55.4
Total Wholesale Revenues						175.4						682.3						123.8						156.8						22.0						17.5						104.0
Other Revenues from Contracts with Customers (d)						9.1						8.9						18.5						26.9						37.3						6.8						5.7
Total Revenues from Contracts with Customers						531.1						691.2						940.2						724.0						904.6						467.6						562.3
Other Revenues:
Alternative Revenue Programs (a) (e)						0.4						50.5						7.2						1.2						12.1						1.8						8.0
Other Revenues (a)						( 0.3 )						0.1						0.2						12.0						2.3						0.1						0.1
Total Other Revenues						0.1						50.6						7.4						13.2						14.4						1.9						8.1
Total Revenues						$	531.2					$	741.8					$	947.6					$	737.2					$	919.0					$	469.5					$	570.4

(a) Amounts include affiliated and nonaffiliated revenues.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $ 36 million primarily related to the PPA with KGPCo.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $ 555 million, $ 22 million and $ 21 million, respectively. The remaining affiliated amounts were immaterial.

(d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $ 18 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

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						Three Months Ended June 30, 2024
						AEP Texas						AEPTCo						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Retail Revenues:
Residential Revenues						$	184.9					$	—					$	364.8					$	190.5					$	465.3					$	187.8					$	120.7
Commercial Revenues						115.0						—						187.1						150.8						276.1						130.1						100.7
Industrial Revenues (a)						34.0						—						205.9						153.1						89.0						91.1						72.3
Other Retail Revenues						9.3						—						28.1						1.3						4.5						25.9						1.7
Total Retail Revenues						343.2						—						785.9						495.7						834.9						434.9						295.4
Wholesale Revenues:
Generation Revenues (b)						—						—						72.1						54.8						—						2.7						50.1
Transmission Revenues (c)						184.8						483.2						45.6						10.0						23.6						10.2						46.7
Total Wholesale Revenues						184.8						483.2						117.7						64.8						23.6						12.9						96.8
Other Revenues from Contracts with Customers (d)						10.4						6.2						13.1						29.4						28.5						12.4						7.6
Total Revenues from Contracts with Customers						538.4						489.4						916.7						589.9						887.0						460.2						399.8
Other Revenues:
Alternative Revenue Programs (a) (e)						1.2						( 14.2 )						( 6.5 )						—						5.3						( 1.4 )						( 4.0 )
Other Revenues (a)						—						—						—						4.4						4.0						—						—
Total Other Revenues						1.2						( 14.2 )						( 6.5 )						4.4						9.3						( 1.4 )						( 4.0 )
Total Revenues						$	539.6					$	475.2					$	910.2					$	594.3					$	896.3					$	458.8					$	395.8

(a) Amounts include affiliated and nonaffiliated revenues.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $ 36 million primarily related to the PPA with KGPCo.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $ 389 million, $ 22 million and $ 15 million, respectively. The remaining affiliated amounts were immaterial.

(d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $ 23 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

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						Six Months Ended June 30, 2025
						VIU						T&D						AEPTHCo						G&M						Corporate and Other						Reconciling Adjustments						AEP Consolidated
						(in millions)
Retail Revenues:
Residential Revenues						$	2,382.0					$	1,350.8					$	—					$	—					$	—					$	—					$	3,732.8
Commercial Revenues						1,414.7						802.3						—						—						—						—						2,217.0
Industrial Revenues (a)						1,322.4						268.2						—						—						—						( 0.5 )						1,590.1
Other Retail Revenues						114.9						29.5						—						—						—						—						144.4
Total Retail Revenues						5,234.0						2,450.8						—						—						—						( 0.5 )						7,684.3
Wholesale and Competitive Retail Revenues:
Generation Revenues						542.3						—						—						89.3						—						—						631.6
Transmission Revenues (b)						278.1						394.4						1,219.7						—						—						( 1,072.3 )						819.9
Retail, Trading and Marketing Revenues (c)						—						—						—						1,160.2						( 0.2 )						( 31.5 )						1,128.5
Total Wholesale and Competitive Retail Revenues						820.4						394.4						1,219.7						1,249.5						( 0.2 )						( 1,103.8 )						2,580.0
Other Revenues from Contracts with Customers (d)						101.0						108.1						17.7						3.4						70.6						( 94.6 )						206.2
Total Revenues from Contracts with Customers						6,155.4						2,953.3						1,237.4						1,252.9						70.4						( 1,198.9 )						10,470.5
Other Revenues:
Alternative Revenue Programs (a) (e)						17.8						15.9						61.3						—						—						( 62.3 )						32.7
Other Revenues (a) (f)						( 20.2 )						7.5						—						60.2						3.8						( 4.2 )						47.1
Total Other Revenues						( 2.4 )						23.4						61.3						60.2						3.8						( 66.5 )						79.8
Total Revenues						$	6,153.0					$	2,976.7					$	1,298.7					$	1,313.1					$	74.2					$	( 1,265.4 )					$	10,550.3

(a) Amounts include affiliated and nonaffiliated revenues.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $ 969 million. The affiliated revenues for Vertically Integrated Utilities were $ 104 million. The remaining affiliated amounts were immaterial.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $ 32 million. The remaining affiliated amounts were immaterial.

(d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $ 55 million. The remaining affiliated amounts were immaterial.

(e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

(f) Generation & Marketing includes economic hedge activity.

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						Six Months Ended June 30, 2024
						VIU						T&D						AEPTHCo						G&M						Corporate and Other						Reconciling Adjustments						AEP Consolidated
						(in millions)
Retail Revenues:
Residential Revenues						$	2,161.3					$	1,354.0					$	—					$	—					$	—					$	—					$	3,515.3
Commercial Revenues						1,294.9						788.1						—						—						—						—						2,083.0
Industrial Revenues (a)						1,299.9						259.1						—						—						—						( 0.3 )						1,558.7
Other Retail Revenues						111.1						27.6						—						—						—						—						138.7
Total Retail Revenues						4,867.2						2,428.8						—						—						—						( 0.3 )						7,295.7
Wholesale and Competitive Retail Revenues:
Generation Revenues						384.9						—						—						51.1						—						—						436.0
Transmission Revenues (b)						241.9						388.1						985.3						—						—						( 815.6 )						799.7
Renewable Generation Revenues (a)						—						—						—						14.5						—						( 2.8 )						11.7
Retail, Trading and Marketing Revenues (c)						—						—						—						1,056.9						0.8						( 69.9 )						987.8
Total Wholesale and Competitive Retail Revenues						626.8						388.1						985.3						1,122.5						0.8						( 888.3 )						2,235.2
Other Revenues from Contracts with Customers (d)						107.1						89.9						14.3						2.3						115.6						( 117.5 )						211.7
Total Revenues from Contracts with Customers						5,601.1						2,906.8						999.6						1,124.8						116.4						( 1,006.1 )						9,742.6
Other Revenues:
Alternative Revenue Programs (a) (e)						( 12.8 )						7.4						( 12.4 )						—						—						( 16.3 )						( 34.1 )
Other Revenues (a) (f)						( 21.4 )						11.9						—						( 93.8 )						( 5.9 )						5.6						( 103.6 )
Total Other Revenues						( 34.2 )						19.3						( 12.4 )						( 93.8 )						( 5.9 )						( 10.7 )						( 137.7 )
Total Revenues						$	5,566.9					$	2,926.1					$	987.2					$	1,031.0					$	110.5					$	( 1,016.8 )					$	9,604.9

(a) Amounts include affiliated and nonaffiliated revenues.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $ 780 million. The affiliated revenues for Vertically Integrated Utilities were $ 83 million. The remaining affiliated amounts were immaterial.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $ 70 million. The remaining affiliated amounts were immaterial.

(d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $ 79 million. The remaining affiliated amounts were immaterial.

(e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

(f) Generation & Marketing includes economic hedge activity.

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						Six Months Ended June 30, 2025
						AEP Texas						AEPTCo						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Retail Revenues:
Residential Revenues						$	352.1					$	—					$	971.6					$	422.2					$	998.7					$	365.7					$	383.9
Commercial Revenues						233.9						—						388.5						344.7						568.5						237.1						296.1
Industrial Revenues (a)						81.2						—						401.9						290.4						187.0						161.7						192.9
Other Retail Revenues						21.0						—						56.4						2.5						8.6						46.6						5.4
Total Retail Revenues						688.2						—						1,818.4						1,059.8						1,762.8						811.1						878.3
Wholesale Revenues:
Generation Revenues (b)						—						—						167.5						333.3						—						5.6						104.3
Transmission Revenues (c)						348.7						1,188.2						87.7						29.0						45.7						29.8						94.3
Total Wholesale Revenues						348.7						1,188.2						255.2						362.3						45.7						35.4						198.6
Other Revenues from Contracts with Customers (d)						18.6						17.8						32.9						56.9						89.6						15.1						15.8
Total Revenues from Contracts with Customers						1,055.5						1,206.0						2,106.5						1,479.0						1,898.1						861.6						1,092.7
Other Revenues:
Alternative Revenue Program (a) (e)						( 1.1 )						62.9						13.7						1.0						17.1						1.9						8.8
Other Revenues (a)						( 0.2 )						—						0.3						( 20.6 )						7.3						—						—
Total Other Revenues						( 1.3 )						62.9						14.0						( 19.6 )						24.4						1.9						8.8
Total Revenues						$	1,054.2					$	1,268.9					$	2,120.5					$	1,459.4					$	1,922.5					$	863.5					$	1,101.5

(a) Amounts include affiliated and nonaffiliated revenues.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $ 81 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $ 962 million, $ 41 million and $ 31 million, respectively. The remaining affiliated amounts were immaterial.

(d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $ 36 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

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						Six Months Ended June 30, 2024
						AEP Texas						AEPTCo						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
Retail Revenues:
Residential Revenues						$	332.2					$	—					$	891.1					$	415.3					$	1,021.8					$	346.0					$	303.1
Commercial Revenues						225.9						—						375.4						295.6						562.2						233.1						240.7
Industrial Revenues (a)						69.6						—						402.3						301.0						189.5						171.4						167.3
Other Retail Revenues						19.0						—						56.2						2.6						8.7						47.4						4.3
Total Retail Revenues						646.7						—						1,725.0						1,014.5						1,782.2						797.9						715.4
Wholesale Revenues:
Generation Revenues (b)						—						—						157.2						192.1						—						4.9						97.2
Transmission Revenues (c)						340.7						958.6						92.7						20.1						47.4						21.0						86.3
Total Wholesale Revenues						340.7						958.6						249.9						212.2						47.4						25.9						183.5
Other Revenues from Contracts with Customers (d)						19.2						14.3						34.8						57.0						70.7						24.4						17.2
Total Revenues from Contracts with Customers						1,006.6						972.9						2,009.7						1,283.7						1,900.3						848.2						916.1
Other Revenues:
Alternative Revenue Programs (a) (e)						( 0.6 )						( 14.9 )						( 6.6 )						( 0.5 )						7.9						( 1.6 )						( 4.1 )
Other Revenues (a)						—						—						0.1						( 21.5 )						11.9						—						—
Total Other Revenues						( 0.6 )						( 14.9 )						( 6.5 )						( 22.0 )						19.8						( 1.6 )						( 4.1 )
Total Revenues						$	1,006.0					$	958.0					$	2,003.2					$	1,261.7					$	1,920.1					$	846.6					$	912.0

(a) Amounts include affiliated and nonaffiliated revenues.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $ 77 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $ 773 million, $ 43 million and $ 28 million, respectively. The remaining affiliated amounts were immaterial.

(d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $ 41 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

Fixed Performance Obligations (Applies to AEP, APCo and I&M)

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of June 30, 2025. Fixed performance obligations primarily include electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrants elected to apply the exemption to not disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less. Due to the annual establishment of revenue requirements, transmission revenues are excluded from the table below. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.

Company						2025						2026-2027						2028-2029						After 2029						Total
						(in millions)
AEP						$	43.7					$	143.6					$	48.6					$	16.1					$	252.0
APCo						8.0						31.9						25.2						11.4						76.5
I&M						2.2						8.8						6.8						2.4						20.2

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Contract Assets and Liabilities

Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have material contract assets as of June 30, 2025 and December 31, 2024.

When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheets in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have material contract liabilities as of June 30, 2025 and December 31, 2024.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrant Subsidiaries’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of June 30, 2025 and December 31, 2024. See “Securitized Accounts Receivable - AEP Credit” section of Note 13 for additional information.

The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets:

						AEP Texas						AEPTCo						APCo						I&M						OPCo						PSO						SWEPCo
						(in millions)
June 30, 2025						$	1.4					$	165.0					$	80.9					$	58.1					$	61.7					$	16.8					$	25.8
December 31, 2024						—						131.6						83.7						55.0						63.6						13.0						21.4

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On May 15, 2025 , Benjamin G. S. Fowke , III, a director of the Company , entered into a Rule 10b5-1 trading agreement (“Rule 10b5-1 Trading Plan”) intended to satisfy the affirmative defense conditions of Rule 10b5‑1(c) of the Securities Exchange Act of 1934. Mr. Fowke’s Rule 10b5-1 Trading Plan provides for an aggregate sale of up to 25,000 shares of common stock through December 12, 2025 .

On May 15, 2025 , Kelly J. Ferneau , the Executive Vice President and Chief Nuclear Officer of the Company , entered into a Rule 10b5-1 Trading Plan intended to satisfy the affirmative defense conditions of Rule 10b5‑1(c) of the Securities Exchange Act of 1934. Ms. Ferneau’s Rule 10b5-1 Trading Plan provides for an aggregate sale of up to 10,218 shares of common stock through February 23, 2026 .

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