As discussed in the 2023 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2023 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2024 and updates the 2023 Annual Report.

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.

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

In March 2023, the Pirkey Plant was retired. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana jurisdictional share of the Pirkey Plant, through a separate rider, through 2032. As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. In July 2023, Texas ALJs issued a PFD that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected the ALJs’ July 2023 PFD. In the open meeting, the commissioners expressed their concerns that the analysis in support of SWEPCo’s decision to retire the Pirkey Plant was not robust enough and that SWEPCo should have re-evaluated the decision following Winter Storm Uri. The treatment of the cost of recovery of the Pirkey Plant is expected to be addressed in a future rate case. As of September 30, 2024, the Texas jurisdictional share of the net book value of the Pirkey Plant was $69 million. To the extent any portion of the Texas jurisdictional share of the net book value of the Pirkey Plant is not recoverable, it could reduce future net income and cash flows and impact financial condition.

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

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, 2024, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $76 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, 2024, 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 2023, the Pirkey Plant was retired. SWEPCo is recovering, or will seek recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of September 30, 2024, SWEPCo’s share of the net investment in the Pirkey Plant was $187 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, 2024, 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.


	AEP
	September 30,		December 31,
	2024		2023
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation	$	156.7	$	125.6
Pirkey Plant Accelerated Depreciation	120.8		114.4
Unrecovered Winter Storm Fuel Costs (a)	75.9		97.2








Storm-Related Costs	41.3		—
Other Regulatory Assets Pending Final Regulatory Approval	16.2		49.8
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	379.5		408.9

Plant Retirement Costs – Asset Retirement Obligation Costs (b)	340.4		25.9
NOLC Costs (c)	82.9		—
2024-2025 Virginia Biennial Under-Earnings	18.6		—
Other Regulatory Assets Pending Final Regulatory Approval	51.3		52.6
Total Regulatory Assets Pending Final Regulatory Approval	$	1,283.6	$	874.4

(c)In the second quarter of 2024, requests seeking to establish a recovery mechanism for these regulatory assets were filed in Indiana, Oklahoma and Texas. In Indiana and Oklahoma, certain intervenors have challenged the recovery, or have proposed ratemaking treatment that would offset the recovery, of the regulatory assets. In the third quarter of 2024, PUCT Staff and certain intervenors in Texas requested a hearing and direct testimony was filed by SWEPCo in October 2024.


	AEP Texas
	September 30,		December 31,
	2024		2023
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Storm-Related Costs	$	41.3	$	—

Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	16.6		37.7
Line Inspection Costs	5.8		5.7
Vegetation Management Program	—		5.2
Texas Retail Electric Provider Bad Debt Expense	—		4.0
Other Regulatory Assets Pending Final Regulatory Approval	1.4		11.7
Total Regulatory Assets Pending Final Regulatory Approval	$	65.1	$	64.3


	APCo
	September 30,		December 31,
	2024		2023
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return


Other Regulatory Assets Pending Final Regulatory Approval	$	1.0	$	0.6
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs (a)	266.9		25.9
Storm-Related Costs – West Virginia	126.5		91.5
2024-2025 Virginia Biennial Under-Earnings	18.6		—
Other Regulatory Assets Pending Final Regulatory Approval	14.7		7.5
Total Regulatory Assets Pending Final Regulatory Approval	$	427.7	$	125.5


	I&M
	September 30,		December 31,
	2024		2023
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return

Other Regulatory Assets Pending Final Regulatory Approval	$	2.3	$	0.2
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs (a)	72.9		—
NOLC Costs – Indiana (b)	24.6		—
Storm-Related Costs – Indiana	7.4		29.7


Other Regulatory Assets Pending Final Regulatory Approval	4.4		3.3
Total Regulatory Assets Pending Final Regulatory Approval	$	111.6	$	33.2


	SWEPCo
	September 30,		December 31,
	2024		2023
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation	$	156.7	$	125.6
Pirkey Plant Accelerated Depreciation	120.8		114.4
Unrecovered Winter Storm Fuel Costs (a)	75.9		97.2



Dolet Hills Power Station Accelerated Depreciation (b)	11.8		12.0
Other Regulatory Assets Pending Final Regulatory Approval	1.0		26.0
Regulatory Assets Currently Not Earning a Return


Storm-Related Costs - Louisiana, Texas	49.0		56.0
NOLC Costs (c)	44.1		—
Other Regulatory Assets Pending Final Regulatory Approval	18.5		13.7
Total Regulatory Assets Pending Final Regulatory Approval	$	477.8	$	444.9

In February 2024, AEP Texas filed a request with the PUCT for a $164 million annual base rate increase over its adjusted test year revenues which include interim transmission and distribution rate updates. AEP Texas’s request is based upon a proposed 10.6% ROE with a capital structure of 55% debt and 45% common equity. The rate case seeks a prudence determination on all capital additions placed in service during the period January 1, 2019 through September 30, 2023. As of September 30, 2024, AEP Texas’ cumulative revenues from transmission and distribution interim rate increases are estimated to be approximately $1.3 billion and are subject to reconciliation in this base rate case. In July 2024, AEP Texas filed an unopposed settlement agreement with the PUCT. The settlement agreement included a proposed annual revenue increase of $70 million based upon a 9.76% ROE with a capital structure of 57.5% debt and 42.5% common equity. In addition, the settlement agreement approved the prudency of capital investments placed in service for the period January 1, 2019 through September 30, 2023 and the associated interim revenues collected on those capital investments. In October 2024, the PUCT issued a final order approving the settlement agreement without modification.

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 to initiate an appeal of this order. In September 2024, oral arguments were held at the West Virginia Supreme Court. A final ruling is expected in the fourth quarter of 2024.

In April 2024, the Companies submitted their annual ENEC update filing with the WVPSC proposing a $58 million annual increase in ENEC rates when compared to existing ENEC rates. The Companies proposed that this ENEC rate change would: (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 July 2024, intervenors and staff filed testimony with the WVPSC, which did not recommend any disallowances.

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 staff 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 of September 30, 2024, APCo had a Virginia jurisdictional under-recovered fuel balance of $164 million. If any fuel costs are not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

In March 2024, APCo filed a request with the Virginia SCC for a $95 million annual increase in base rates based upon a proposed 10.8% ROE and a proposed capital structure of 51% debt and 49% common equity. The requested increase in base rates is primarily due to incremental rate base, proposed capital structure changes including an increase in ROE and proposed increases in distribution and generation operation and maintenance expenses. In September 2024, a hearing was held where APCo updated its requested increase in base rates to $64 million consistent with its rebuttal positions or, alternatively, an increase of $45 million if annual environmental compliance consumable expenses are moved from base rates to recovery through APCo’s environmental rate adjustment clause. An order will be issued in the fourth quarter of 2024. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

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 expense over a three-year period, 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 including: (a) the Companies’ remaining combined unrecovered ENEC balance related to costs incurred through February 28, 2023, (b) undepreciated West Virginia jurisdictional plant balances as of December 31, 2022 for the Amos, Mitchell and Mountaineer Plants, (c) environmental costs previously approved for recovery through a separate West Virginia surcharge and (d) deferred major storm operation and maintenance costs. Securitization of those items could reduce the Companies’ combined requested increase in annual base rates to $37 million.

The Companies also included an alternative ratemaking proposal that includes: (a) a separate surcharge that would allow the Companies up to a 3% annual increase in overall West Virginia rates for four consecutive years on April 1st 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 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. If any refund liabilities are imposed by the WVPSC, it could reduce future net income and cash flows and impact financial condition.

In late September 2024, the remnants of Hurricane Helene significantly impacted APCo’s Virginia and West Virginia service territories leading to approximately 260,000 customer outages and damages to APCo’s power grid. Storm restoration efforts continued into early October and APCo completed restoration efforts for all customers who lost power by October 6th, 2024. As of September 30, 2024, APCo incurred approximately $19 million ($13 million related to the Virginia jurisdiction and $6 million related to the West Virginia jurisdiction) of incremental other operation and maintenance expenses and approximately $8 million of capital expenditures. APCo deferred $16 million of the incremental other operation and maintenance expenses as regulatory assets as the costs are deemed probable of future recovery. Based on the information currently available, APCo estimates total storm restoration costs to be approximately $140 million, of which 70% is expected to be deferred as regulatory assets and the remaining 30% of the costs are expected to be capital expenditures. If any costs related to Hurricane Helene 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 September 30, 2024, AEP’s share of ETT’s cumulative revenues that are subject to a prudency review is approximately $1.8 billion. A base rate review could produce a refund to customers if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. ETT is required to file for a comprehensive rate review no later than February 1, 2025, during which the $1.8 billion of cumulative revenues above will be subject to review.

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 and the Rockport UPA with AEGCo ranging from $3 million to $15 million. A hearing is scheduled for December 2024. If any PSCR costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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

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

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

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. In July 2024, I&M submitted its FAC filing and earnings test evaluation for the period ended May 2024. In September 2024, an intervenor submitted testimony suggesting that I&M failed to prorate calculations of I&M’s operating income and I&M’s earnings test ceiling to reflect the impact of I&M’s updated Indiana base rates that became effective in May 2024. The IURC is expected to issue an order in November 2024. As of September 30, 2024, I&M’s financial statements adequately reflect the estimated impact of upcoming Indiana earnings test filings, including Indiana’s jurisdictional share of PTCs that have been recognized in 2024. If the IURC issues orders on I&M’s Indiana earnings test(s) that result in refunds to customers, it could reduce 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 net income and cash flows and impact financial condition.

In June 2023, KPCo filed a request with the KPSC for a $94 million net annual increase in base rates based upon a proposed 9.9% ROE with the increase to be implemented no earlier than January 2024. In conjunction with its June 2023 filing, KPCo further requested to finance through the issuance of securitization bonds, approximately $471 million of regulatory assets. KPCo’s proposal did not address the disposition of its 50% interest in Mitchell Plant, which will be addressed in the future. As of September 30, 2024, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $552 million. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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

In January 2024, consistent with the November 2023 uncontested settlement agreement, the KPSC issued a financing order approving KPCo’s request to securitize certain regulatory assets balances as of the time securitization bonds are issued and concluding that costs requested for recovery through securitization were prudently incurred. The KPSC’s financing order includes certain additional requirements related to securitization bond structuring, marketing, placement and issuance that were not reflected in KPCo’s proposal. In accordance with Kentucky statutory requirements and the financing order, the issuance of the securitized bonds is subject to final review by the KPSC after bond pricing. KPCo expects to proceed with the securitized bond issuance process and to complete the securitization process in the first half of 2025, subject to market conditions. As of September 30, 2024, regulatory asset balances expected to be recovered through securitization total $485 million and include: (a) $297 million of plant retirement costs, (b) $79 million of deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, (c) $49 million of deferred purchased power expenses, (d) $58 million of under-recovered purchased power rider costs and (e) $2 million of deferred issuance-related expenses, including KPSC advisor expenses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In December 2023, KPCo received intervenor testimony in its FAC review for the two-year period ending October 31, 2022, recommending a disallowance ranging from $44 million to $60 million of its total $432 million purchased power cost recoveries as a result of proposed modifications to the ratemaking methodology that limits purchased power costs recoverable through the FAC. A hearing was held in February 2024 and the KPSC may issue its order in the fourth quarter of 2024 or early 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.

In January 2024, KPCo filed an application with the KPSC seeking to recover an allowed cost (Rockport Offset) of $41 million in accordance with the terms of the settlement agreement in the 2017 Kentucky Base Rate Case permitting KPCo to use the level of non-fuel, non-environmental Rockport Plant UPA expense included in base rates to earn its authorized ROE in 2023 since the Rockport UPA ended in December 2022. An estimated Rockport Offset of $23 million was recovered through a rider, subject to true-up, during the 12-months ended December 2023. In February 2024, the KPSC issued an order allowing KPCo to collect the remaining $18 million through interim rates, subject to refund, over twelve months starting in March 2024. In April 2024, KPCo submitted to the KPSC a request for decision on the record. In August 2024, KPCo filed an application with the KPSC to extend the recovery of the remaining balance through September 2025. The KPSC may issue its order in the fourth quarter of 2024 or early 2025. Through the third quarter of 2024, the Rockport Offset true-up is reflected in revenues to the extent amounts have been billed to customers, as KPCo has not met the requirements of alternative revenue recognition in accordance with the accounting guidance for “Regulated Operations”. If the Rockport Offset is not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

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

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

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

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. An order is expected in the fourth quarter of 2024. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

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

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

The PUCT’s December 2023 approval of the preliminary order determined that it will address, in the ongoing PUCT remand proceeding, any potential revenue refunds to customers that may be required by future PUCT orders. On March 1, 2024, SWEPCo filed supplemental direct testimony with the PUCT in response to the December 2023 preliminary order. On March 8, 2024, intervenors and the PUCT staff filed a motion with the PUCT to strike portions of SWEPCo’s October 2023 direct testimony and March 2024 supplemental direct testimony. On March 19, 2024, the ALJ granted portions of the motion, which included removal of testimony supporting SWEPCo’s position that refunds were not appropriate. On March 28, 2024,

SWEPCo filed an appeal of the ALJ decision with the PUCT. In April 2024, intervenors and PUCT staff submitted testimony recommending customer refunds through December 2023 ranging from $149 million to $197 million, including carrying charges, with refund periods ranging from 18 months to 48 months. In May 2024, the PUCT denied SWEPCo’s appeal of the ALJ’s March 2024 decision. In the second quarter of 2024, based on the PUCT’s decision, SWEPCo recorded a one-time, probable revenue refund provision of $160 million, including interest, associated with revenue collected from February 2013 through December 2023. In June 2024, SWEPCo and parties to the remand proceeding reached an agreement in principle that would resolve all issues in the case. In October 2024, SWEPCo filed the settlement agreement with the PUCT. Under the settlement agreement, SWEPCo will refund over a two-year period $148 million, including interest, associated with revenue collected from February 2013 through December 2023 and remove AFUDC in excess of the Texas jurisdictional capital cost cap from rate base. The settlement is expected to be considered by the PUCT in the fourth quarter of 2024.

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

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

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.

In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC, which confirmed the prudency of $150 million of deferred incremental storm restoration

expenses. The agreement also authorized an interim carrying charge at a rate of 3.125% through March 2024. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. In April 2024, SWEPCo and the LPSC staff filed a joint uncontested stipulation and settlement agreement with the LPSC requesting securitization of storm costs, including a storm reserve. In July 2024, the LPSC issued an order approving the joint uncontested stipulation and settlement agreement, including approval to securitize $343 million, which includes $180 million for storm costs and a $150 million storm reserve. Securitization bonds are expected to be issued in the fourth quarter of 2024, subject to market conditions.

The NCWF are subject to various regulatory performance requirements, including a Net Capacity Factor (NCF) guarantee. The NCF guarantee will be measured in MWhs across all facilities on a combined basis for each five year period for the first thirty full years of operation. The first NCF guarantee five year period began in April 2022. Certain wind turbines have experienced performance issues related to defects covered by the manufacturer’s warranty. These performance issues have prompted PSO and SWEPCo to file a lawsuit against the manufacturer in an attempt to find a resolution on the matter. If regulatory performance requirements, such as the NCF guarantee, are not met, PSO and SWEPCo may recognize a regulatory liability to refund retail customers. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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

In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. PJM continues to evaluate reliability and market efficiency in the area. As of September 30, 2024, AEP’s share of IEC capital expenditures was approximately $94 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is cancelled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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

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

The Registrants transitioned to stand-alone treatment of NOLCs in its PJM and SPP transmission formula rates beginning with the 2022 projected transmission revenue requirements and 2021 true-up to actual transmission revenue requirements, and provided notice of this change in informational filings made with the FERC. Stand-alone treatment of the NOLCs for transmission formula rates increased the annual revenue requirements for years 2024, 2023, 2022 and 2021 by $52 million, $61 million, $69 million and $78 million, respectively.

In January 2024, the FERC issued two orders granting formal challenges by certain unaffiliated customers related to stand-alone treatment of NOLCs in the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP. The FERC directed the AEP transmission owning subsidiaries within PJM and SPP to provide refunds with interest on all amounts collected for the 2021 rate year, and for such refunds to be reflected in the annual update for the next rate year. Accordingly, in the third quarter of 2024, the AEP transmission owning subsidiaries within SPP provided a portion of the 2021 rate year refunds, with the remainder of the refunds expected to be provided in 2025. The AEP transmission owning subsidiaries within PJM are expected to provide their respective refunds for the 2021 rate year in 2025. In February 2024, AEPSC on behalf of the AEP transmission owning subsidiaries within PJM and SPP filed requests for rehearing. In March 2024, the FERC denied AEPSC’s requests for rehearing of the January 2024 orders by operation of law and stated it may address the requests for rehearing in future orders. In March 2024, AEPSC submitted refund compliance reports to the FERC, which preserve the non-finality of the FERC’s January 2024 orders pending further proceedings on rehearing and appeal. In April 2024, AEPSC made filings with the FERC which request that the FERC: (a) reopen the record so that the FERC may take the IRS PLRs received in April 2024 regarding the treatment of stand-alone NOLCs in ratemaking into evidence and consider them in substantive orders on rehearing and (b) stay its January 2024 orders and related compliance filings and refunds to provide time for consideration of the April 2024 IRS PLRs. In May 2024, AEPSC filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit seeking review of the FERC’s January 2024 and March 2024 decisions. In July 2024, the FERC issued orders approving AEPSC’s request to reopen the record for the limited purpose of accepting into the record the IRS PLRs and establish additional briefing procedures. In August 2024, AEPSC filed briefs with the FERC requesting the commission modify or overturn their initial orders.

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