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RATE MATTERS | 9 Months Ended
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Sep. 30, 2025
Regulated Operations [Abstract] |
RATE MATTERS | RATE MATTERS 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 2025 Arkansas Base Rate Case. In August 2025 and October 2025, APSC staff and certain intervenors recommended recovery of the Arkansas jurisdictional share of the remaining net book value of the Pirkey Plant over 20 years with no debt or equity return. See the “2025 Arkansas Base Rate Case” section below for additional information. 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 this conclusion in the ALJ’s July 2023 PFD. 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. See the “2025 Texas Base Rate Case” section below for additional information. As of September 30, 2025, the Arkansas and Texas jurisdictional shares of the net book value of the Pirkey Plant were $117 million. To the extent any portion of the Arkansas and Texas jurisdictional shares of the net book value of the Pirkey Plant are 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 CCN with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively. The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of September 30, 2025, of generating facilities planned for retirement:
Plant |  |  |  |  |  | Net Book Value |  | Accelerated Depreciation Regulatory Asset |  |  |  | Cost of Removal Regulatory Liability |  |  | Projected Retirement Date |  |  | Current Authorized Recovery Period |  | Annual Depreciation (a)
|  |  |  |  |  | (dollars in millions)
Northeastern Plant, Unit 3 |  |  |  |  |  | $ | 73.9 |  |  | $ | 212.8 |  |  |  |  | $ | 21.2 |  | (b) |  | 2026 |  |  | (c) |  | $ | 16.1 |
Welsh Plant, Units 1 and 3 |  |  |  |  |  | 278.8 |  |  | 206.2 |  |  |  |  | 57.6 |  | (d) |  | 2028 | (e) |  | (f) |  | 46.5 |
(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 September 30, 2025, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $67 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 September 30, 2025, SWEPCo had a net under-recovered fuel balance of $23 million, inclusive of costs related to the Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event. In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $35 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of up to $55 million, including denial of recovery of the $35 million deferral, with refunds to customers over five years. In February 2024, an ALJ issued a final recommendation which included a proposed $55 million refund to customers and the denial of recovery of the $35 million deferral. SWEPCo filed a motion to present oral arguments with the LPSC to dispute the ALJ’s recommendations. In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the fuel recovery dispute and resulted in a fuel disallowance of $11 million. The remaining $24 million regulatory asset balance will be recovered over three years with interest. In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause. In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $48 million of Oxbow mine related costs through 2035. If any of these costs are not recoverable or customer refunds are required, it could reduce future net income and cash flows and impact financial condition. Pirkey Plant and Related Fuel Operations (Applies to AEP and SWEPCo) In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or is seeking recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of September 30, 2025, SWEPCo’s share of the net investment in the Pirkey Plant was $206 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 September 30, 2025, SWEPCo had a net under-recovered fuel balance of $23 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. In July 2025, the PUCT issued an order approving the settlement agreement. If any of these costs are not recoverable or customer refunds are required, it could reduce future net income and cash flows and impact financial condition. Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)
|  | AEP
|  | September 30, |  | December 31,
|  | 2025 |  | 2024
Noncurrent Regulatory Assets |  | (in millions)
Regulatory Assets Currently Earning a Return |  |  |  |
Welsh Plant, Units 1 and 3 Accelerated Depreciation |  | $ | 206.2 |  |  | $ | 168.6 |
Pirkey Plant Accelerated Depreciation |  | 134.1 |  |  | 121.3 |
Storm-Related Costs |  | 53.5 |  |  | 51.0 |
Unrecovered Winter Storm Fuel Costs (a) |  | 47.2 |  |  | 70.7 |
Unified Tracking Mechanism Deferred Costs |  | 39.2 |  |  | — |
Other Regulatory Assets Pending Final Regulatory Approval |  | 30.9 |  |  | 20.7 |
Regulatory Assets Currently Not Earning a Return |  |  |  |
Plant Retirement Costs – Asset Retirement Obligation Costs (b) |  | 386.5 |  |  | 357.4 |
Storm-Related Costs (c) |  | 202.2 |  |  | 300.8 |
2024-2025 Virginia Biennial Under-Earnings |  | 166.0 |  |  | 78.4 |
NOLC Costs (d) |  | 95.9 |  |  | 92.8 |
Other Regulatory Assets Pending Final Regulatory Approval |  | 130.8 |  |  | 86.3 |
Total Regulatory Assets Pending Final Regulatory Approval | $ | 1,492.5 |  |  | $ | 1,348.0 |
(a)Includes $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of September 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)Includes $40 million of West Virginia jurisdictional storm operation and maintenance costs as of September 30, 2025 that are subject to a future final securitization financing order from the WVPSC. (d)Approved for collection through rates, subject to refund, for the Oklahoma and SWEPCo-Texas jurisdictions.
|  | AEP Texas
|  | September 30, |  | December 31,
|  | 2025 |  | 2024
Noncurrent Regulatory Assets |  | (in millions)
Regulatory Assets Currently Earning a Return |  |  |  |
Storm-Related Costs |  | $ | 41.3 |  |  | $ | 41.3 |
Unified Tracking Mechanism Deferred Costs |  | 39.2 |  |  | — |
System Resiliency Plan Deferred Costs |  | 8.6 |  |  | — |
Regulatory Assets Currently Not Earning a Return |  |  |  |
Storm-Related Costs |  | 34.4 |  |  | 13.1 |
Deferred Pension and OPEB Costs |  | 24.7 |  |  | 15.6 |
Line Inspection Costs |  | 5.8 |  |  | 5.8 |
Other Regulatory Assets Pending Final Regulatory Approval |  | 2.9 |  |  | 1.3 |
Total Regulatory Assets Pending Final Regulatory Approval |  | $ | 156.9 |  |  | $ | 77.1 |
|  | APCo
|  | September 30, |  | December 31,
|  | 2025 |  | 2024
Noncurrent Regulatory Assets |  | (in millions)
Regulatory Assets Currently Earning a Return |  |  |  |
Other Regulatory Assets Pending Final Regulatory Approval |  | $ | 1.5 |  |  | $ | 1.1 |
Regulatory Assets Currently Not Earning a Return |  |  |  |
Plant Retirement Costs – Asset Retirement Obligation Costs (a) |  | 305.8 |  |  | 282.1 |
2024-2025 Virginia Biennial Under-Earnings |  | 166.0 |  |  | 78.4 |
Storm-Related Costs – West Virginia (b) |  | 49.6 |  |  | 144.2 |
Pension Settlement |  | 16.7 |  |  | 17.8 |
Virginia Retail Consumables Deferral |  | 12.3 |  |  | — |
Other Regulatory Assets Pending Final Regulatory Approval |  | 20.7 |  |  | 11.9 |
Total Regulatory Assets Pending Final Regulatory Approval |  | $ | 572.6 |  |  | $ | 535.5 |
(a)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information. (b)Includes $40 million of West Virginia jurisdictional storm operation and maintenance costs as of September 30, 2025 that are subject to a future final securitization financing order from the WVPSC.
|  | I&M
|  | September 30, |  | December 31,
|  | 2025 |  | 2024
Noncurrent Regulatory Assets |  | (in millions)
Regulatory Assets Currently Earning a Return |  |  |  |
Other Regulatory Assets Pending Final Regulatory Approval |  | $ | 3.3 |  |  | $ | 6.4 |
Regulatory Assets Currently Not Earning a Return |  |  |  |
Plant Retirement Costs – Asset Retirement Obligation Costs (a) |  | 77.4 |  |  | 74.0 |
Storm-Related Costs – Indiana |  | 29.3 |  |  | 6.3 |
NOLC Costs – Indiana (b) |  | — |  |  | 26.7 |
Other Regulatory Assets Pending Final Regulatory Approval |  | 1.7 |  |  | 1.6 |
Total Regulatory Assets Pending Final Regulatory Approval |  | $ | 111.7 |  |  | $ | 115.0 |
(a)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information. (b)In the first quarter of 2025, the IURC approved the stand-alone treatment of NOLCs.
|  | OPCo
|  | September 30, |  | December 31,
|  | 2025 |  | 2024
Noncurrent Regulatory Assets |  | (in millions)
Regulatory Assets Currently Earning a Return |  |  |  |
Other Regulatory Assets Pending Final Regulatory Approval |  | $ | 0.9 |  |  | $ | 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 |  | $ | 0.9 |  |  | $ | 0.5 |
|  | PSO
|  | September 30, |  | December 31,
|  | 2025 |  | 2024
Noncurrent Regulatory Assets |  | (in millions)
Regulatory Assets Currently Not Earning a Return |  |  |  |
NOLC Costs (a) |  | $ | 25.4 |  |  | $ | 16.4 |
Storm-Related Costs |  | 22.4 |  |  | 4.9 |
Generation PBA and Delayed Retirement Deferral |  | 7.7 |  |  | — |
Pension Settlement |  | 7.4 |  |  | 7.8 |
Other Regulatory Assets Pending Final Regulatory Approval |  | 7.8 |  |  | 1.2 |
Total Regulatory Assets Pending Final Regulatory Approval |  | $ | 70.7 |  |  | $ | 30.3 |
(a)Approved for collection through rates, subject to refund.
|  | SWEPCo
|  | September 30, |  | December 31,
|  | 2025 |  | 2024
Noncurrent Regulatory Assets |  | (in millions)
Regulatory Assets Currently Earning a Return |  |  |  |
Welsh Plant, Units 1 and 3 Accelerated Depreciation |  | $ | 206.2 |  |  | $ | 168.6 |
Pirkey Plant Accelerated Depreciation |  | 134.1 |  |  | 121.3 |
Unrecovered Winter Storm Fuel Costs (a) |  | 47.2 |  |  | 70.7 |
Dolet Hills Power Station Accelerated Depreciation (b) |  | 12.4 |  |  | 11.8 |
Storm-Related Costs |  | 12.2 |  |  | 9.7 |
Other Regulatory Assets Pending Final Regulatory Approval |  | 4.3 |  |  | 1.1 |
Regulatory Assets Currently Not Earning a Return |  |  |  |
NOLC Costs (c) |  | 70.5 |  |  | 49.6 |
Storm-Related Costs - Louisiana, Texas |  | 44.9 |  |  | 39.9 |
Other Regulatory Assets Pending Final Regulatory Approval |  | 19.5 |  |  | 18.7 |
Total Regulatory Assets Pending Final Regulatory Approval |  | $ | 551.3 |  |  | $ | 491.4 |
(a)Includes $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of September 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)Approved for collection through rates, subject to refund, for Texas jurisdiction. If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP and AEP Texas) AEP Texas Interim Transmission and Distribution Rates Through September 30, 2025, AEP Texas’ cumulative revenues from transmission and distribution interim base rate increases that are subject to review are estimated to be approximately $79 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 UTM 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 UTM 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. As a result of the new legislation, AEP Texas deferred approximately $39 million of eligible costs through September 2025 as a regulatory asset. In October 2025, AEP Texas submitted its first filing with the PUCT seeking recovery of eligible costs through the UTM established by HB 5247. This filing combined three recovery mechanisms (Interim Transmission Cost of Service and Distribution Cost Recovery Factor capital trackers and the Transmission Cost Recovery Factor) into a single filing. The capital tracker incremental revenue requirement sought in this filing is $109 million, including a request to recover, over a 12-month period, $42 million of eligible costs related to UTM deferrals and $2 million of eligible costs related to the System Resiliency Plan deferrals, both inclusive of equity carrying charges through the July 2025 test year period end. 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. 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 remand cases further describing its calculations of the ordered $232 million disallowance. In June 2025, the Companies submitted direct testimony on remand supporting a reduction to the WVPSC’s previously-ordered disallowance of at least $179 million. In August 2025, WVPSC staff and an intervening party submitted testimony recommending the continued disallowance of $232 million of ENEC under-recovered costs as of February 28, 2023, with the intervening party recommending that the WVPSC consider a larger disallowance based on alleged imprudence of coal procurement. A hearing on the 2021-2023 ENEC remand cases was held in October 2025. If any additional 2021-2023 ENEC costs are not recoverable or refunds are ordered, it would reduce future net income and cash flows and impact financial condition. 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. In April 2025, the Companies submitted their 2025 ENEC update filing proposing a $72 million annual increase in ENEC rates. In September 2025, the WVPSC issued an order on the Companies’ 2025 ENEC update filing approving an annual ENEC revenue requirement increase of $70 million with no change in ENEC rates charged to customers. The WVPSC ordered this ENEC customer rate increase to occur upon securitization which is expected in the first half of 2026 as further described in the “2025 West Virginia Securitization Filing” section below. The WVPSC denied an intervenor-recommended ENEC under-recovery disallowance of $19 million. 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 fourth 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 submitted 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. In August 2025, the WVPSC issued an order on the Companies’ base case filing. The WVPSC’s order: (a) approved a combined annual base rate revenue requirement increase of $76 million ($67 million related to APCo) based on a 9.25% ROE and a capital structure of 56% debt and 44% equity, (b) included recovery of $24 million of previously deferred storm costs with no carrying charges, with future securitization of these deferred storm costs as described in the “2025 West Virginia Securitization Filing” section below, (c) included a decrease in the base rates revenue requirement related to a WVPSC-ordered decrease in depreciation rates, (d) required the Companies to recover the monthly level of this base rate increase through current ENEC rates, (e) effectively terminated the Companies’ MRBC, Mitchell Base Rate and Vegetation Management surcharges upon the approved change in base rates revenue requirement with these surcharges rolled into base rates, (f) stipulated that the Companies’ proposals related to the inclusion of a stand-alone NOLC deferred tax asset in rate base will be addressed in a future proceeding upon the Companies’ receipt of a PLR from the IRS and (g) approved the Companies’ requested West Virginia jurisdictional environmental and capital investment tracker but did not approve the Companies’ proposed storm tracking mechanism, annual 3% surcharge increase and freezing of OATT revenues in the ENEC. In September 2025, the Companies filed a petition for reconsideration with the WVPSC to explain the financial consequences of the order and seek clarification on certain issues. 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. 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 Commission did not rule on MRBC refunds proposed by WVPSC Staff and an intervening party related to NOLC and other issues as these issues will be addressed in a future filing. The WVPSC’s August 2025 base case order stipulated that the Companies’ proposals related to the inclusion of a stand-alone NOLC deferred tax asset in rate base will be addressed in a future proceeding upon the Companies’ receipt of a PLR from the IRS. 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 balances, (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 deferred major storm operation and maintenance costs. In August 2025, the WVPSC issued an interim order stating that it will approve the Companies’ future securitization of the generation plant assets, ENEC under-recovery balances, environmental costs and deferred storm operation and maintenance costs. In September 2025, and as directed by the WVPSC in the August 2025 interim order described above, the Companies submitted an updated proposed financing order that reflected additional ENEC under-recovery balances for costs incurred in 2025 and additional storm operation and maintenance deferral balances for the impacts of Hurricane Helene and winter storms Blair, Harlow and Jett. WPCo forecasted CCR and ELG amounts below related to the Mitchell Plant are subject to change pending a fourth quarter 2025 KPSC ruling on KPCo’s June 2025 CPCN filing that 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. See “Mitchell Plant Filing for Certificate of Public Convenience and Necessity” section below for additional information. All amounts in the table below are subject to further review in a future final securitization financing order that the Companies expect will be issued by the WVPSC in the fourth quarter of 2025. See the summarization of the proposed securitization items 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 |  | 166.6 |  |  | 245.8 |  |  | 412.4 |
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 |  | 155.0 |  |  | 2.9 |  |  | 157.9 |
Upfront Financing Costs |  | 10.4 |  |  | 5.9 |  |  | 16.3 |
Total |  | $ | 1,565.1 |  |  | $ | 962.5 |  |  | $ | 2,527.6 |
Upon receipt of the final financing order, the Companies expect to proceed with the securitization bonds issuance process and to complete the securitization in the first 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. 2025 Virginia Securitization Filing 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 September 2025, Virginia SCC staff submitted testimony concluding that all costs proposed by APCo for securitization are eligible for securitization in accordance with Virginia law. While also concluding that APCo’s proposed securitization of the Amos and Mountaineer Plants over 20 years offers benefits to customers through rate relief, Virginia SCC staff took no position on APCo’s proposed securitization of major storm other operation and maintenance expenses due to the apparent lack of significant benefit or cost savings for customers. In October 2025, the Hearing Examiner recommended the Virginia SCC approve the requested $1.4 billion for securitization. The Virginia SCC’s final order is due in November 2025. ETT Rate Matters (Applies to AEP) 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 was based upon a proposed 10.6% ROE with a capital structure of 55% debt and 45% common equity. The rate case sought 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 included 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 included 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. In October 2025, the PUCT issued an order approving the June 2025 settlement. The rates approved by the order are identical to the rates approved on an interim basis. I&M Rate Matters (Applies to AEP and I&M) Michigan Power Supply Cost Recovery (PSCR) Reconciliation 2023 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. 2024 PSCR Reconciliation In March 2025, I&M submitted its 2024 PSCR Reconciliation to the MPSC. In October 2025, MPSC staff and intervenors submitted testimony recommending PSCR cost disallowances associated with the OVEC ICPA and the Rockport UPA with AEGCo ranging from $259 thousand to $14 million. A hearing on I&M’s 2024 PSCR Reconciliation is scheduled for December 2025 and 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. 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. In July 2025, I&M submitted its FAC filing and earnings test evaluation for the period ended May 2025. I&M proposed an over-earnings credit to customers for the earnings test period ending May 2025 of $35 million. 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 from January 2024 through the February 2025 update in base rates. In April 2025, KPCo filed an appeal with the Circuit Court for a motion to enforce in response to the KPSC’s denial to recover PJM transmission costs incurred from January 2024 through the implementation of new rates. In September 2025, the Circuit Court issued an order granting KPCo’s motion to enforce. In October 2025, the KPSC issued an order approving recovery of the $16 million of PJM transmission costs, with debt and equity carrying charges starting September 15, 2025 on the remaining PJM transmission costs to be recovered, through a rider. The rider will be effective with the first billing cycle in November 2025 and will be in place for 22 months. 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 securitized plant retirement costs as ordered by the KPSC. 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 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 October 2025, intervenor testimony was filed that recommended approval of the CPCN. A hearing is scheduled for November 2025 and an order is expected in December 2025. As of September 30, 2025, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal and including CWIP and inventory, was $529 million. If any costs related to this CPCN filing are disallowed, it could reduce future net income and cash flows and impact financial condition. 2025 Kentucky Base Rate Case In August 2025, KPCo filed a request with the KPSC for a $96 million net annual increase in base rates based upon a proposed 10% ROE and a proposed capital structure of 53.9% debt and 46.1% common equity, to be implemented no earlier than March 2026. Among other changes, the filing proposes 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 includes 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 has historically been 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. 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. 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. Oral arguments are scheduled for December 2025. 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. A hearing is scheduled for November 2025. 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, through the third quarter of 2025, OPCo recorded a $24 million reduction to its OVEC-related purchased power regulatory asset for deferred net costs that are no longer probable of future recovery. Management is unable 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 (ESRR). In October 2025, the PUCO staff filed its required report recommending a net annual decrease in distribution base rates ranging, from $12 million to $28 million, based upon an ROE range of 9.33% to 9.84%. The PUCO staff recommended the exclusion of $59 million of certain utility investments and $55 million of capitalized incentives from rate base, and a reduction in employee-related expenses of $23 million. In addition, the PUCO staff recommended increases to the DIR revenue cap and ESRR cost cap that were less than OPCo’s requested increases. Responses to the PUCO staff report are due in November 2025 and a hearing is scheduled for January 2026. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition. 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. 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 |  | September 30, 2025 |  | December 31, 2024 |  | Approved Recovery Period |  | Approved Carrying Charge
|  | (in millions) |  |  |  |
Arkansas |  | $ | 25.1 |  |  | $ | 37.2 |  |  | 6 years |  | (a)
Louisiana |  | 47.2 |  |  | 70.6 |  |  | (b) |  | (b)
Texas |  | 49.6 |  |  | 72.7 |  |  | 5 years |  | 1.65%
Total |  | $ | 121.9 |  |  | $ | 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. In August 2025 and October 2025, APSC staff and intervenors filed testimony recommending an annual base rate increase ranging from $53 million to $99 million with a 9.5% ROE. APSC staff recommended a capital structure of 54.8% debt and 45.2% common equity. APSC staff and certain intervenors recommended recovery of the $37 million Arkansas jurisdictional share of the remaining net book value of the Pirkey Plant over 20 years with no debt or equity return. 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. 2025 Texas Base Rate Case In October 2025, SWEPCo filed a request with the PUCT for a $164 million annual increase in Texas base rates based upon a 10.75% ROE and a proposed capital structure of 48% debt and 52% common equity. The request would move certain revenues recovered through riders, including interim revenues on transmission and distribution investment since the 2020 Texas Base Rate Case, into base rates resulting in a net annual rate increase of $95 million. The proposed net annual increase includes recovery of the Texas jurisdictional share of the retired Pirkey Plant through depreciation expense and requests $21 million annually to recover deferred storm costs and maintain a storm catastrophe reserve. 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 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. In October 2025, the Maryland Public Service Commission approved an extension of the construction commencement deadline to May 2026. Additional regulatory proceedings before the PAPUC are expected to resume in 2025 or 2026. 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 September 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. Requests for rehearing were filed by intervenors in July 2025. 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 associated with the AEP transmission owning subsidiaries within PJM and filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit seeking review of the FERC’s June 2025 order. 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. In October 2025, a settlement agreement was filed with the FERC. If the FERC finalizes the settlement agreement as proposed, management anticipates the results of the order will not have a material impact on financial condition, results of operations or cash flows. Transmission Agreement Cost Allocation Complaint (Applies to AEP, APCo, I&M and OPCo) In March 2025, the KPSC and the Attorney General of Kentucky filed a complaint at the FERC against AEPSC and the AEP East Companies challenging the manner in which costs are allocated for local transmission projects pursuant to the TA. The complaint contends that certain costs allocated to KPCo are unjust, unreasonable and provide no benefit to KPCo customers. The relief requested in the complaint includes requiring a revision to the TA so that the costs for local transmission projects remain exclusively with the retail distribution service territory where the project is located unless a specific project is granted approval to establish a different cost allocation by the state commissions. Various parties have filed comments and motions to intervene. In May 2025, AEP filed a motion to dismiss and answered the complaint. If the FERC orders a change in the way costs are allocated pursuant to the TA it could impact future net income, cash flows and financial condition. FERC Audit (Applies to AEP and SWEPCo) SWEPCo is currently under audit by FERC’s Division of Audits and Accounting. The audit is evaluating SWEPCo’s compliance with 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. Management is unable to predict the outcome of the audit. If any refund liabilities are imposed by the FERC or any disallowances occur, it would reduce future net income and cash flows and financial condition.

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