As discussed in the 2025 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2025 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2026 and updates the 2025 Annual Report.

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management regularly evaluates cost estimates of complying with these regulations in balance with reliability and other factors, which has resulted in, and in the future may result in, a proposal to retire generating facilities earlier than their currently estimated useful lives.

In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or is seeking recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of March 31, 2026, SWEPCo’s share of the net investment in the Pirkey Plant was $172 million, including materials and supplies, net of cost of removal. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions.

As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment of the Pirkey Plant net investment. SWEPCo requested recovery including a weighted average cost of capital carrying charge in its 2025 Arkansas Base Rate Case. In January 2026, the APSC approved a settlement agreement providing for the recovery of the Pirkey Plant net investment over 10 years with a 3% return, and the agreement also included a provision that the retirement of the Pirkey Plant was prudent.

In July 2023, the LPSC ordered that a separate proceeding be established to review the prudence of the decision to retire the Pirkey Plant, including the costs included in fuel for years starting in 2019 and after. In April 2025, the LPSC determined the retirement of the Pirkey Plant was reasonable and prudent and authorized continued recovery of and on the remaining balance of the Pirkey Plant at SWEPCo’s weighted average cost of capital through 2032.

In July 2023, Texas ALJs issued a PFD that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected the July 2023 PFD conclusion. SWEPCo requested recovery of the Texas jurisdictional share of the remaining net book value of the Pirkey Plant in its 2025 Texas Base Rate Case. In April 2026, a unanimous settlement in principle was reached related to the 2025 Texas Base Rate Case. In March 2026, SWEPCo recorded approximately $31 million for a probable partial regulatory disallowance of the Pirkey Plant. See the “2025 Texas Base Rate Case” section below for additional information. As of March 31, 2026, the Texas jurisdictional share of the net book value of the Pirkey Plant was $46 million. To the extent the PUCT does not accept the settlement and any costs included in this filing are not approved for recovery as a result of the final PUCT order, it could reduce future net income and cash flows and impact financial condition.

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset.

Following the 2024 Oklahoma Base Rate Case, PSO continues to recover Northeastern Plant, Unit 3 through 2040. In April 2025, PSO and the ODEQ finalized a second amended regional haze agreement that would allow continued operation of the Northeastern Plant, Unit 3, on natural gas, through May 31, 2041. This agreement is contingent upon approval by the Federal EPA in the form of a revised SIP, which the ODEQ has submitted. In anticipation of approval from the Federal EPA, PSO began operating Northeastern Plant, Unit 3 on natural gas in January 2026. In the first quarter of 2026, PSO retired $325 million of coal-related assets at Northeastern Plant, Unit 3, resulting in a decrease to both Total Property, Plant and Equipment and Accumulated Depreciation and Amortization. As of March 31, 2026, the unrecovered value of these assets was $152 million, inclusive of ARO costs, which PSO is currently collecting in rates.

In November 2020, management announced that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation. In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively. In February 2026, the APSC issued an order approving the application for a CCN.


	AEP
	March 31,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation	$	235	$	220
UTM Deferred Costs	80		56
Pirkey Plant Accelerated Depreciation	46		93








Storm-Related Costs	48		43
West Virginia MRBC Surcharge (a)	34		—
System Resiliency Plan Deferred Costs - Texas	31		17
Other Regulatory Assets Pending Final Regulatory Approval	21		6
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs (b)	273		191
Plant Retirement Costs – Asset Retirement Obligation Costs (c)	263		257
2024-2025 Virginia Biennial Under-Earnings (d)	192		172
NOLC Costs (e)	87		89
Pension Settlement	24		24
Deferred Pension and OPEB Costs	32		27
Other Regulatory Assets Pending Final Regulatory Approval	134		112
Total Regulatory Assets Pending Final Regulatory Approval	$	1,500	$	1,307

(a)In April 2026, the WVPSC issued an order that affirms previously approved MRBC revenue requirements and allows APCo to perform a final true-up to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner. The timing of recovery through the ENEC will be determined in the Companies’ 2026 ENEC proceeding. See “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” section below for additional information.


	AEP Texas
	March 31,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
UTM Deferred Costs	$	80	$	56
Storm-Related Costs	41		41

System Resiliency Plan Deferred Costs	20		17

Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	34		31
Deferred Pension and OPEB Costs	32		27



Other Regulatory Assets Pending Final Regulatory Approval	9		9
Total Regulatory Assets Pending Final Regulatory Approval	$	216	$	181


	APCo
	March 31,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
West Virginia MRBC Surcharge (a)	$	28	$	—

Other Regulatory Assets Pending Final Regulatory Approval	2		2
Regulatory Assets Currently Not Earning a Return
2024-2025 Virginia Biennial Under-Earnings (b)	192		172
Plant Retirement Costs – Asset Retirement Obligation Costs (c)	173		169
Storm-Related Costs – West Virginia (d)	62		39
Pension Settlement	16		16
2026-2027 Virginia Biennial Under-Earnings	15		—
Virginia Corporate Alternative Minimum Tax	—		13
West Virginia Corporate Alternative Minimum Tax	—		11

Other Regulatory Assets Pending Final Regulatory Approval	29		18
Total Regulatory Assets Pending Final Regulatory Approval	$	517	$	440


	I&M
	March 31,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return

Other Regulatory Assets Pending Final Regulatory Approval	$	4	$	4
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs (a)	79		78
Storm-Related Costs – Indiana	32		29



Other Regulatory Assets Pending Final Regulatory Approval	6		7
Total Regulatory Assets Pending Final Regulatory Approval	$	121	$	118


	PSO
	March 31,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)




Regulatory Assets Currently Not Earning a Return


Storm-Related Costs	$	32	$	25
NOLC Costs (a)	21		23
Generation PBA and Delayed Retirement Deferral	17		13
Oklahoma Senate Bill 998 Deferral	16		9

Other Regulatory Assets Pending Final Regulatory Approval	15		14
Total Regulatory Assets Pending Final Regulatory Approval	$	101	$	84


	SWEPCo
	March 31,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation	$	235	$	220
Pirkey Plant Accelerated Depreciation	46		93


Retired Plant Costs - FERC	15		—
System Resiliency Plan Deferred Costs - Texas	11		1

Other Regulatory Assets Pending Final Regulatory Approval	7		2
Regulatory Assets Currently Not Earning a Return


Storm-Related Costs - Louisiana, Texas	88		43
NOLC Costs (a)	65		66
Other Regulatory Assets Pending Final Regulatory Approval	21		20
Total Regulatory Assets Pending Final Regulatory Approval	$	488	$	445

Through March 31, 2026, AEP Texas’ cumulative revenues from transmission and distribution interim base rate increases that are subject to review are estimated to be approximately $159 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.

In October 2025, AEP Texas submitted its first filing with the PUCT seeking recovery of eligible costs through the UTM. In March 2026, a Texas ALJ issued a PFD recommending partial disallowance of the requested amounts. In April 2026, AEP Texas filed responses reflective of the legislative intent of Texas House Bill 5247 (2025). The impact of the final decision, and

In March 2026, AEP Texas began billing interim rates subject to refund as part of the UTM filing. If the PUCT issues a ruling that differs from AEP Texas’ position, a refund or billing credit could be required. Investments included in the UTM and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate review before the PUCT. AEP Texas deferred approximately $80 million of eligible costs through March 31, 2026 as a regulatory asset. If any of these deferred costs are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

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 September 2025, and in response to the WVPSC’s August 2025 order on the Companies’ 2024 West Virginia Base Rate Case, petitions for reconsideration were filed with the WVPSC to explain the financial consequences of the order and seek clarification on certain issues. In February 2026, the WVPSC issued an order upon reconsideration approving a revised ROE of 9.75%. This approved change in ROE results in a revision to the approved annual increase in base rates from $76 million ($67 million related to APCo) to $91 million ($79 million related to APCo) effective February 20, 2026. All other requests for reconsideration were rejected by the WVPSC.

In March 2024, APCo and WPCo (the Companies) submitted an annual MRBC surcharge update filing with the WVPSC requesting a $32 million annual increase in the Companies’ combined MRBC rates. The MRBC is an infrastructure investment tracker that allows limited cost recovery related to capital investments between the Companies’ West Virginia jurisdictional base rate cases. WVPSC staff and an intervening party recommended revenue requirement disallowances in written and verbal testimony and briefs for certain ratemaking issues used to develop the Companies’ proposed MRBC rates, including the West Virginia jurisdictional effect of state deferred income taxes, NOLCs and AROs.

The WVPSC’s August 2025 order on the Companies’ West Virginia base case filing, as described in the “2024 West Virginia Base Rate Case” section above, approved the termination of the MRBC and the transition of MRBC rates into base rates. The WVPSC did not rule on MRBC refunds proposed by WVPSC staff and an intervening party related to NOLCs and other issues.

recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner during the four-year existence of the surcharge. This order also allows the Companies to recognize a carrying charge on revised MRBC under-recovery balances starting September 2024 and for the Companies to recover the updated MRBC under-recovery with carrying charges through current ENEC surcharge rates over a period to be determined in the Companies’ 2026 ENEC proceeding. The April 2026 order also noted that collection of revenue requirement related to inclusion of a stand-alone NOLC deferred tax asset in MRBC rates may be subject to refund, pending the future issuance of a PLR or other guidance by the IRS. If any refund liabilities are imposed by the WVPSC related to NOLC, it could reduce future net income and cash flows and impact financial condition.

In March 2026, the WVPSC issued a final financing order approving the Companies’ proposed securitization of the following: (a) remaining combined unrecovered ENEC balances, (b) undepreciated West Virginia jurisdictional plant balances as of December 31, 2022 for the Amos, Mitchell and Mountaineer Plants, (c) undepreciated environmental costs previously approved for recovery through a separate West Virginia surcharge and (d) West Virginia jurisdictional deferred major storm operation and maintenance costs. As included in the WVPSC’s March 2026 order, shown below is a summary of the Companies’ combined $2.6 billion maximum securitization amount:


Proposed Securitized Items	APCo		WPCo		Total
	(in millions)
Undepreciated Utility Plant Balances of Amos, Mitchell and Mountaineer (as of December 31, 2022)	$	1,145	$	559	$	1,704
ENEC Under-Recovery Regulatory Assets (a)	216		276		492
Forecasted Undepreciated CCR and ELG Investments of Amos, Mitchell and Mountaineer (as of November 30, 2024) (a)(b)	88		149		237
Deferred Storm Other Operation and Maintenance Expense Regulatory Assets (b)	155		3		158
Upfront Financing Costs (a)	10		6		16
Total	$	1,614	$	993	$	2,607

(b)In December 2025, the KPSC approved KPCo’s request for a CPCN to make investments necessary for KPCo to resume: (a) a 50% share of the Mitchell Plant ELG Project and (b) a 50% share of non-ELG capital investments. This approval by the KPSC allows KPCo to continue taking a 50% share of energy and capacity from the Mitchell Plant to serve KPCo customers beyond December 31, 2028. See “Mitchell Plant Filing for Certificate of Public Convenience and Necessity” section below for additional information. In February 2026, WPCo requested that the WVPSC grant any additional authorizations necessary to enable WPCo to reflect the holdings and impact of the December 2025 KPSC order or make a determination that no such authorizations are required. WPCo forecasted CCR and ELG amounts related to the Mitchell Plant are subject to change pending a ruling from the WVPSC on WPCo’s February 2026 filing.

In accordance with the West Virginia statutory requirements and the financing order, the issuance of the securitization bonds is subject to final review by the WVPSC after bond pricing. The Companies will proceed with the securitization bond issuance process and plan to complete the securitization in the second half of 2026, subject to market conditions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In July 2025, APCo filed a request with the Virginia SCC to finance, through the issuance of proposed 20-year 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. In November 2025, the Virginia SCC issued a financing order approving securitization of the requested $1.4 billion of Virginia jurisdictional costs. In accordance with Virginia statutory requirements and the financing order, the issuance of the securitization bonds is subject to final review by the Virginia SCC after bond pricing. APCo expects to proceed with the securitization bond issuance process and to complete the securitization process in the second quarter of 2026, subject to market conditions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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 March 31, 2026, AEP’s share of ETT’s cumulative revenues from interim base rate increases that are subject to a prudency review is approximately $1 million. A base rate review could produce a refund to customers if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition.

In April 2026, ETT filed a request with the PUCT for a $42 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request is based upon a proposed 10.5% ROE with a capital structure of 55% debt and 45% common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates. A procedural schedule for the case is pending. If any of the costs in the case are not recoverable or refunds collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition.

In March 2025, I&M submitted its 2024 PSCR Reconciliation to the MPSC. In October 2025, MPSC staff and intervenors submitted testimony recommending PSCR cost disallowances associated with the OVEC ICPA and the Rockport UPA with AEGCo ranging from $259 thousand to $14 million. A hearing on I&M’s 2024 PSCR Reconciliation was held in December 2025. In April 2026, an ALJ issued a PFD recommending a $2 million cost disallowance associated with the OVEC ICPA and no cost associated with the Rockport UPA with AEGCo. An MPSC order is expected in the second quarter of 2026. Any future disallowances ordered by the MPSC on I&M’s 2024 PSCR Reconciliation could reduce future net income and cash flows and impact financial condition.

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 Indiana earnings test requirements previously established by the IURC. If future IURC orders require that I&M provide credits in the FAC factor computation in excess of established earnings test requirements, it could reduce future net income and cash flows and impact financial condition.

In February 2026, I&M submitted its FAC filing and earnings test evaluation for the period ended November 2025. I&M proposed an over-earnings credit to customers for the earnings test period ending November 2025 of $53 million based on requested modifications to jurisdictional cost allocations to more accurately reflect I&M’s cost to serve Indiana retail customers. In April 2026, I&M and an intervening party submitted a settlement agreement recommending that the IURC approve I&M’s proposed modifications to jurisdictional cost allocations and proposed over-earnings credit of $53 million for the earnings test period ending November 2025. A hearing will be held in May 2026 and an IURC order is expected in the second quarter of 2026. An IURC order approving I&M’s proposed jurisdictional cost allocation modifications as included in the settlement agreement would increase future net income and cash flows and impact financial condition.

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.

KPCo and WPCo each own a 50% undivided interest in the 1,560 MW coal-fired Mitchell Plant. In July 2021, the KPSC rejected KPCo’s ELG compliance plan for KPCo’s 50% ownership share of ELG investments at the Mitchell Plant that would allow KPCo to take capacity and energy to serve customers beyond December 31, 2028. As a result of this order, and pursuant to September 2022 resolutions under the existing Mitchell Plant Operating Agreement, WPCo funded 100% of the Mitchell Plant ELG investments that have been placed in service. In addition, WPCo also paid for a greater than 50% share of certain non-ELG capital investments made at Mitchell Plant which will continue to be used in the operation of Mitchell Plant beyond 2028.

In June 2025, KPCo filed a request with the KPSC for a CPCN to make investments necessary to reflect: (a) a 50% share of the Mitchell Plant ELG Project and (b) a 50% share of non-ELG capital investments. KPSC approval of these investments would allow KPCo to continue taking a 50% share of energy and capacity from the Mitchell Plant to serve KPCo customers beyond December 31, 2028. KPCo proposed to recover the estimated $78 million investment in the ELG Project through KPCo’s existing Environmental Surcharge and requested recovery of an estimated $60 million of Mitchell Plant non-ELG capital investments through its 2025 Kentucky Base Rate Case filing. See “2025 Kentucky Base Rate Case” section below for additional information.

In November 2025, KPCo and an intervening party submitted a settlement agreement that recommended the approval of KPCo’s proposed Mitchell Plant CPCN and use of KPCo’s Environmental Surcharge to recover Mitchell Plant ELG project costs through 2040. The settlement agreement further recommended granting KPCo authority to defer the depreciation expense and carrying costs associated with Mitchell Plant non-ELG capital investments to a regulatory asset until it can be reflected in rates. The recovery mechanism for Mitchell Plant non-ELG capital investments will be addressed in KPCo’s 2025 Kentucky Base Rate Case filing. See “2025 Kentucky Base Rate Case” section below for additional information.

To operate in accordance with KPSC and WVPSC directives related to Mitchell Plant ELG investments, KPCo and WPCo expect to utilize existing authority under the Mitchell Plant Operating Agreement to revise billing procedures resulting in equal allocation of costs. In February 2026, WPCo requested that the WVPSC grant any additional authorizations necessary to enable WPCo to reflect the holdings and impact of the December 2025 KPSC order or make a determination that no such authorizations are required. As of March 31, 2026, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal and including CWIP and inventory, and prior to the effect of revised billing procedures expected under the Mitchell Plant Operating Agreement to comply with the KPSC’s December 2025 order, was $517 million.

In August 2025, KPCo filed a request with the KPSC for a $96 million net annual increase in base rates based upon a proposed 10% ROE and a proposed capital structure of 53.9% debt and 46.1% common equity, to be implemented no earlier than March 2026. Among other changes, the filing proposed a $10 million increase in PJM transmission costs, a $9 million increase due to load loss and a $6 million increase in depreciation rates.

The proposed annual rate increase also included a $20 million annual revenue requirement related to KPCo’s investment in the Mitchell Plant. See “Mitchell Plant Filing for Certificate of Public Convenience and Necessity” section above for additional information. As part of this filing, KPCo requested a new generation rider to recover the remaining net book value of KPCo’s non-environmental investment in the Mitchell Plant that KPCo historically recovered through base rates. If the generation rider is approved, the $20 million would be removed from the requested revenue requirement increase and would be collected through the rider. Additionally, KPCo is pursuing securitization legislation that would allow KPCo to securitize the remaining net book value of the Mitchell Plant. If the securitization of the remaining Mitchell Plant net book value is successful, collection of costs through the generation rider would cease.

9.8% authorized ROE and a capital structure of 53.9% debt and 46.1% common equity, and (b) a new generation rider with a first year revenue requirement of $18 million based on a 9.7% authorized ROE to recover non-environmental plant investments at Mitchell Plant and all incremental capital investments after May 31, 2025 at both Mitchell Plant and Big Sandy Plant. Capital and other operation and maintenance expenses related to any new generating assets also will be eligible for inclusion in the Generation Rider, subject to KPSC approval. The settlement revenue requirement will be reduced by $25 million in the first year and $15 million in the second year through a new rider that returns certain unprotected deferred tax expenses in customer rates on a temporary basis, and then beginning in the third year, collects the deferred tax expense amounts from customers over the estimated time period that taxes are due to the IRS. The settlement agreement also proposes: (a) approval to defer all storm other operation and maintenance expenses above or below the level included in base rates, and (b) approval to defer vegetation management costs above or below the level included in base rates, capped at a total of $45 million in 2026 and $52 million in 2027. Consistent with the KPSC order in KPCo’s 2023 Kentucky Base Rate Case filing, the settlement agreement also provides that KPCo’s proposal to include a stand-alone NOLC deferred tax asset in rate base will be addressed in a future proceeding upon KPCo’s receipt of a PLR or other guidance from the IRS. A hearing was held in January 2026.

In February 2026, the KPSC issued an order modifying the January 2026 settlement agreement and approving an annual increase of $55 million in Kentucky retail rates based upon a 9.75% base rate ROE effective March 1, 2026. This increase is inclusive of a $36 million increase in base rates and a $19 million increase due to the new generation rider. The order reduced the settlement revenue requirement by $22 million primarily due to a $10 million reduction related to FERC transmission expense and a $9 million reduction in incentive and other compensation. Additionally, the KPSC ordered that $47 million of certain vegetation management costs previously incurred and capitalized from January 2018 through May 2025 should be reclassified as a regulatory asset to be recovered over a 30 year period with no carrying costs, and that prospective vegetation management costs incurred should no longer be capitalized but instead be treated as operating expense.

In March 2026, KPCo filed a request with the KPSC seeking rehearing on the vegetation management finding in the base case order in addition to certain other denied costs. In April 2026, the KPSC issued an order approving KPCo’s request for rehearing and set a procedural schedule for submitting information requests. Additionally, the order authorized KPCo to defer $17 million of certain vegetation management costs previously incurred and capitalized from June 2025 through February 2026 to a regulatory asset, pending the KPSC’s final decision on rehearing. If any costs included in the request for rehearing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

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

In August 2024, the PUCO issued orders pertaining to the OVEC cost recovery audits that: (a) denied intervenors’ application for rehearing on the 2016-2017 audit period, (b) determined costs incurred by OPCo during the 2018-2019 audit period were prudent, (c) determined costs incurred by OPCo during the 2020 audit period were prudent and (d) recommended no disallowances for any mentioned audit period in question. In September 2024, intervenors filed for rehearing on the 2018-2019 and 2020 OVEC cost recovery audit periods claiming the PUCO’s August 2024 orders to adopt the findings of the audit reports were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In October 2024, the PUCO denied the intervenors’ applications for rehearing of the 2018-2019 and 2020 audit periods. In December 2024, intervenors filed appeals with the Supreme Court of Ohio on the PUCO’s denial for rehearing. In April 2026, the Supreme Court of Ohio issued a decision affirming the PUCO’s August 2024 order which determined costs incurred by OPCo during the 2018-2019 audit period were prudent.

In February and March 2025, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2021-2023 audit period were imprudent and should be disallowed. Management disagrees with these claims and is unable to predict the impact of these disputes. An evidentiary hearing was held in November 2025 and post-hearing briefs were submitted in February 2026. If any costs are disallowed or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

In January 2026, OPCo, the PUCO staff, and certain intervenors filed a settlement agreement with the PUCO. After incorporating reductions to rider rates, the settlement reflects an annual net revenue increase of $11 million based upon a 9.84% ROE and a capital structure of 49.1% debt and 50.9% common equity while also securing a reduction in customer rates through the amortization of $82 million of deferred tax regulatory liabilities over 18 months, an item not included in the original application. The resulting overall annual revenue impact is a net decrease of $59 million. The difference between OPCo’s requested annual base rate increase and the settlement is primarily due to a reduction in the requested ROE. Additionally, the agreement proposed increased revenue caps for the Distribution Investment Rider, annual cost cap increases in the Enhanced Service Reliability Rider and would result in no material disallowances. In April 2026, the PUCO issued an order approving the joint stipulation and settlement agreement and rates went into effect. In May 2026, two intervenors filed applications for rehearing.

In March 2026, the service territory of OPCo was impacted by strong winds from an isolated storm resulting in power outages and damage to the transmission and distribution infrastructure. As of March 31, 2026, OPCo had incurred approximately $20 million in incremental operation and maintenance costs related to service restoration efforts. The incremental storm restoration costs have been deferred as a regulatory asset and OPCo expects to seek future recovery of those costs through its approved storm cost recovery mechanism.

In January 2026, PSO filed a request with the OCC for a $299 million annual base rate increase based upon a 10.5% ROE with a capital structure of 50.1% debt and 49.9% common equity, net of existing rider revenue and certain incremental renewable facility benefits expected to be provided to customers through riders. PSO also requested an expanded transmission cost recovery rider and a new vegetation management rider. Further, PSO is seeking approval of new large load special terms and conditions in the Large Power and Light tariff.

In May 2026, various intervenors and staff filed testimony supporting an annual base rate increase ranging from $10 million to $109 million based on a recommended ROE ranging from 8.3% to 9.38%. The primary differences between PSO’s requested annual increase in base rates and staff and intervenors’ recommendations include: (a) a reduction in the proposed ROE, (b) modifications to PSO’s previously approved treatment of a stand-alone NOLC deferred tax asset in rate base, (c) treatment of storm costs and (d) adjustments to PSO's proposed depreciation and amortization.

In October 2025, SWEPCo filed a request with the PUCT for a $164 million annual increase in Texas base rates based upon a 10.75% ROE and a proposed capital structure of 48% debt and 52% common equity. The request would move certain revenues recovered through riders, including interim revenues on transmission and distribution investment since the 2020 Texas Base Rate Case, into base rates resulting in a net annual rate increase of $95 million. The proposed net annual increase includes recovery of the Texas jurisdictional share of the retired Pirkey Plant through depreciation expense and requests $21 million annually to recover deferred storm costs and expand the utility’s self-insurance reserve for potential losses and damages.

In March 2026, various intervenors filed testimony supporting a reduction to SWEPCo's net request ranging from $36 million to $64 million based on a recommended ROE ranging from 9.25% to 9.44%. In March 2026, PUCT staff filed testimony supporting a reduction to SWEPCo's net request of $26 million based on an ROE of 9.6%. The primary differences between SWEPCo’s requested annual increase in base rates and staff and intervenors’ recommendations include: (a) recovery of Pirkey Plant, (b) modifications to SWEPCo’s previously approved treatment of a stand-alone NOLC deferred tax asset in rate base and (c) a reduction in the proposed ROE.

The NCWF are subject to various regulatory performance requirements, including a Net Capacity Factor (NCF) guarantee. The NCF guarantee measures in MWhs across all facilities on a combined basis for each five year period for the first thirty full years of operation. The first NCF guarantee five year period began in April 2022. Certain wind turbines experienced performance issues that prompted PSO and SWEPCo to file a lawsuit against the manufacturer, which led to an agreement between PSO and SWEPCo and the manufacturer that addressed the performance issues. If regulatory performance requirements, such as the NCF guarantee, are not met, PSO and SWEPCo may recognize a regulatory liability associated with a refund to retail customers.

In 2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan to alleviate congestion. Transource Energy has an ownership interest in the IEC, which is located in Maryland and Pennsylvania. In June 2020, the Maryland Public Service Commission approved a CPCN to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PAPUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy appealed the PAPUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. In May 2022, the Pennsylvania state court issued an order affirming the PAPUC decision as to state law claims. In December 2023, the United States District Court for the Middle District of Pennsylvania granted summary judgment in favor of Transource Energy, finding that the PAPUC decision violated federal law and the United States Constitution. In January 2024, the PAPUC filed an appeal of the district court’s grant of summary judgment with the United States Court of Appeals for the Third Circuit. In September 2025, the United States Court of Appeals for the Third Circuit affirmed the December 2023 district court order in favor of Transource Energy. The Pennsylvania Attorney General subsequently petitioned to intervene, which the United States Court of Appeals for the Third Circuit denied. The Pennsylvania Attorney General sought review of the United States Court of Appeals for the Third Circuit’s denial at the United States Supreme Court, which is pending.

In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC had not been canceled and remained necessary to alleviate congestion. In July 2025, PJM removed the IEC from suspended status and indicated the project going forward will be included in PJM’s models with a modified scope. PJM continues to evaluate reliability and market efficiency in the area. As of March 31, 2026, AEP’s share of IEC capital expenditures was approximately $96 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.

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:

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

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

In June 2025, the FERC issued two orders, partially reversing its January 2024 decisions on the basis of IRS PLRs accepted into the record, and concluding that the accelerated depreciation-related NOLC adjustments should be included in rate base and should also be included in the computation of Excess ADIT regulatory liabilities to be refunded to customers. Requests for rehearing were filed by intervenors in July 2025 and were rejected by FERC on the merits in November 2025. In March 2026, an intervenor filed a formal challenge and complaint regarding the NOLC adjustments in the 2025 annual update covering the transmission formula rates for 2024 in PJM. Intervenors have filed petitions for review of the FERC’s orders in this matter with the United States Court of Appeals for the District of Columbia Circuit. The appeals have been consolidated and are pending the establishment of a procedural schedule.

As directed by the FERC in its June 2025 order, AEP transmission owning subsidiaries within PJM and SPP submitted compliance filings in August 2025 that revised the March 2024 refund compliance reports and permit the collection of excess refunds provided to customers, with interest, in the annual update for the 2025 rate year. In October 2025, intervenors filed comments in response to the compliance filings. In March and April 2026, the FERC approved the AEP transmission owning subsidiaries’ compliance filings related to PJM and SPP, respectively.

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


	AEP		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Total Revenues	$	270	$	214	$	6	$	11	$	—	$	6	$	27
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(24)		—		(17)		—		—		—		—
Other Operation	53		—		15		(6)		—		19		10
Income (Loss) Before Income Tax Expense (Benefit)	241		214		8		17		—		(13)		17
Income Tax Expense (Benefit)	(313)		(203)		(21)		(28)		—		(16)		(39)
Net Income	554		417		29		45		—		3		56
Net Income Attributable to Noncontrolling Interest	55		55		—		—		—		—		—
Earnings Attributable to Common Shareholder	$	499	$	362	$	29	$	45	$	—	$	3	$	56

In March 2025, the KPSC and the Attorney General of Kentucky filed a complaint at the FERC against AEPSC and the AEP East Companies challenging the manner in which costs are allocated for local transmission projects pursuant to the TA. The complaint contends that certain costs allocated to KPCo are unjust, unreasonable and provide no benefit to KPCo customers. The relief requested in the complaint includes requiring a revision to the TA so that the costs for local transmission projects remain exclusively with the retail distribution service territory where the project is located unless a specific project is granted approval to establish a different cost allocation by the state commissions. Various parties have filed comments and motions to intervene. In May 2025, AEP filed a motion to dismiss and answered the complaint. In November 2025, the FERC issued an order denying the KPSC and Attorney General of Kentucky complaint. In December 2025, the KPSC and Attorney General of Kentucky requested a rehearing of the November order denying the complaint. In January 2026, the FERC issued a notice of denial of the request for rehearing by operation of law, providing the FERC with additional time to consider and decide on the merits of the request. In February 2026, the KPSC and Attorney General of Kentucky filed a petition for review of the FERC’s orders in this matter with the United States Court of Appeals for the Sixth Circuit. In March 2026, the FERC again denied the complaint, continuing to find that the KPSC and Attorney General of Kentucky have not met their burden of proof. If the FERC orders a change in the way costs are allocated pursuant to the TA it could impact future net income, cash flows and financial condition.

The FERC Division of Audits and Accounting initiated an audit of SWEPCo in April 2024 evaluating certain accounting and reporting requirements under various FERC regulations, including compliance with the approved terms, rates and conditions of its SPP transmission formula rate mechanism. In March 2026, the FERC issued a final audit report which included, among other things, findings and recommendations related to SWEPCo's policy for the capitalization of certain vegetation management costs.

As a result of the final audit report, effective starting the first quarter of 2026, AEP will no longer capitalize the vegetation management costs identified in the FERC finding on a prospective basis. AEP's PJM and SPP transmission formula rates will provide recovery of these costs as an expense effective with the 2026 rate year. Retail ratemaking for these costs will be determined in current or future ratemaking proceedings in each jurisdiction which may allow the continued capitalization of these costs as property, plant and equipment or deferral as regulatory assets. Management is unable to predict the outcome in any current or future ratemaking proceeding. If any refund liabilities are imposed by any retail commission or any disallowances occur, it would reduce future net income and cash flows and impact financial condition.