As discussed in the 2022 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2022 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 2023 and updates the 2022 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 which has resulted in, and in the future may result in, a decision to retire coal-fired 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. 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. See “2020 Texas Base Rate Case” and “2020 Louisiana Base Rate Case” sections below for additional information.

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. The Texas jurisdictional share of the Pirkey Plant will be addressed in SWEPCo’s next base rate case.

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 part of the 2021 Oklahoma Base Rate Case, PSO will continue to recover Northeastern Plant, Unit 3 through 2040.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses and are subject to prudency determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of June 30, 2023, SWEPCo had a net under-recovered fuel balance of $120 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 $34 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 $72 million, including denial of recovery of the $34 million deferral, with refunds to customers over five years. In September 2022, SWEPCo filed rebuttal testimony addressing the LPSC staff recommendations and a hearing was held in May 2023.

In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or will seek recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of June 30, 2023, SWEPCo’s share of the net investment in the Pirkey Plant was $177 million, including materials and supplies, net of cost of removal. See the “Regulated Generating Units that have been Retired” section above for additional information. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of March 31, 2023, SWEPCo fuel deliveries, including billings of all fixed costs, from Sabine ceased. Additionally, as of June 30, 2023, SWEPCo had a net under-recovered fuel balance of $120 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 June 2023, an unopposed settlement agreement was filed with the PUCT that would provide recovery of $33 million of Sabine related fuel costs through 2035. In July 2023, Texas ALJs issued a proposal for decision that concluded the decision to retire the Pirkey Plant was prudent. A decision from the PUCT on the unopposed settlement agreement and the Texas ALJ proposal for decision is expected in the second half of 2023.


	AEP
	June 30,		December 31,
	2023		2022
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Pirkey Plant Accelerated Depreciation	$	111.8	$	116.5
Unrecovered Winter Storm Fuel Costs (a)	109.5		121.7


Welsh Plant, Units 1 and 3 Accelerated Depreciation	105.4		85.6

Dolet Hills Power Station Fuel Costs - Louisiana	33.9		32.0
Texas Mobile Generation Costs	29.4		17.6


Other Regulatory Assets Pending Final Regulatory Approval	21.4		19.3
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs (b)(c)(d)	395.4		407.2
2020-2022 Virginia Triennial Under-Earnings	35.0		37.9
Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		25.9
Other Regulatory Assets Pending Final Regulatory Approval	49.3		55.6
Total Regulatory Assets Pending Final Regulatory Approval	$	917.0	$	919.3


	AEP Texas
	June 30,		December 31,
	2023		2022
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Texas Mobile Generation Costs	$	29.4	$	17.6
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	34.9		26.7
Vegetation Management Program	5.2		5.2
Texas Retail Electric Provider Bad Debt Expense	4.1		4.1
Other Regulatory Assets Pending Final Regulatory Approval	13.6		13.4
Total Regulatory Assets Pending Final Regulatory Approval	$	87.2	$	67.0


	APCo
	June 30,		December 31,
	2023		2022
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
COVID-19 – Virginia	$	7.2	$	7.0

Regulatory Assets Currently Not Earning a Return
Storm-Related Costs - West Virginia	72.0		72.6
2020-2022 Virginia Triennial Under-Earnings	35.0		37.9
Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		25.9
Other Regulatory Assets Pending Final Regulatory Approval	5.5		1.1
Total Regulatory Assets Pending Final Regulatory Approval	$	145.6	$	144.5


	I&M
	June 30,		December 31,
	2023		2022
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval	$	0.1	$	0.1
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs - Indiana	23.9		21.6


Other Regulatory Assets Pending Final Regulatory Approval	2.7		2.0
Total Regulatory Assets Pending Final Regulatory Approval	$	26.7	$	23.7


	SWEPCo
	June 30,		December 31,
	2023		2022
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Pirkey Plant Accelerated Depreciation	$	111.8	$	116.5
Unrecovered Winter Storm Fuel Costs (a)	109.5		121.7

Welsh Plant, Units 1 and 3 Accelerated Depreciation	105.4		85.6

Dolet Hills Power Station Fuel Costs - Louisiana	33.9		32.0
Dolet Hills Power Station	12.1		9.7
Other Regulatory Assets Pending Final Regulatory Approval	1.9		2.5
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs (b)(c)	48.0		151.5
Asset Retirement Obligation - Louisiana	—		11.8
Other Regulatory Assets Pending Final Regulatory Approval	15.9		16.0
Total Regulatory Assets Pending Final Regulatory Approval	$	438.5	$	547.3

Through June 30, 2023, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is approximately $791 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. AEP Texas is required to file for a comprehensive rate review no later than April 5, 2024.

In March 2023, APCo submitted its 2020-2022 Virginia triennial review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $213 million annual increase in Virginia base rates based upon a proposed 10.6% return on common equity. The requested annual increase includes $47 million related to vegetation management and a $35 million increase in depreciation expense. The requested increase in depreciation expense reflects, among other things, the impacts of incremental investments made since APCo’s last depreciation study using property balances as of December 31, 2022. Effective January 1, 2023 and in accordance with past Virginia SCC directives, APCo implemented updated Virginia depreciation rates. APCo’s proposed revenue requirement also includes the recovery of certain costs incurred that partially contributed to APCo’s calculated earnings shortfall for the 2020-2022 triennial period. For triennial review periods in which a Virginia utility earns below its authorized ROE band, the utility may file to recover expenses incurred, up to the bottom of the authorized ROE band, related to certain categories of costs, including major storm costs for severe weather events. As of June 30, 2023, APCo deferred approximately $35 million related to previously incurred major storm costs as a result of APCo’s calculation of Virginia earnings below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period.

In July 2023, intervening parties submitted testimony recommending a $69 million annual Virginia base rate increase based on the following significant adjustments: (a) a 9.2% ROE, (b) a $36 million decrease in depreciation expense using a 2040 estimated Amos Plant retirement date for Virginia ratemaking purposes rather than the 2032/2033 retirement date requested by APCo, (c) the removal of $40 million of APCo’s requested increase in vegetation management expense, (d) the removal of $23 million in major storm expenses incurred during the 2020-2022 triennial period, and (e) the removal of $15 million of forecasted spending related to boiler maintenance and generation consumables expense. Virginia staff testimony is due in the third quarter of 2023 and a Virginia SCC order will be issued in the fourth quarter of 2023.

In April 2021, APCo and WPCo (the Companies) requested a combined $73 million annual increase in ENEC rates based on a cumulative $55 million ENEC under-recovery as of February 28, 2021 and an $18 million increase in projected ENEC costs for the period September 2021 through August 2022. In September 2021, the WVPSC issued an order approving a $7 million overall increase in ENEC rates, including an approval for recovery of the Companies’ cumulative $55 million ENEC under-recovery balance and a $48 million reduction in projected costs for the period September 2021 through August 2022. Subsequently, the Companies submitted a request for reconsideration of this order, identifying flaws in the WVPSC’s calculation of forecasted future year fuel expense and purchased power costs.

In March 2022, the WVPSC issued an order granting the Companies’ request for reconsideration, in part, and approving $31 million in projected costs for the period September 2021 through August 2022. The order also reopened the 2021 ENEC case to require the Companies to explain the significant growth in the reported under-recovery of ENEC costs and to provide various other information including revised projected costs for the period March 2022 through August 2022. Also, in March 2022, the Companies filed testimony providing the information requested in the WVPSC’s order and requested a $155 million annual increase in ENEC rates effective May 1, 2022. In May 2022, the WVPSC issued an order approving a $93 million overall increase to ENEC rates to recover projected annual ENEC costs. However, the WVPSC stated that actual and projected ENEC costs are still subject to a prudency review.

In September 2022, following an agreed upon delay in the proceedings of the Companies’ 2022 ENEC case, certain intervenors submitted testimony recommending disallowances of at least $83 million to the Companies’ historical period ENEC under-recovery balance along with proposals to either securitize the Companies’ remaining ENEC balance or defer recovery of this balance beyond the traditional one-year period. West Virginia staff recommended a $13 million increase in ENEC rates pending the outcome of the ENEC prudency review. In February 2023, the WVPSC issued an order stating that the commission will not grant additional rate increases for fuel costs until the WVPSC staff completes its prudency review.

In April 2023, the Companies submitted their 2023 annual ENEC filing with the WVPSC, proposing two alternatives to increase ENEC rates effective September 1, 2023. The first alternative is a $293 million annual increase in ENEC rates comprised of an $89 million increase for current year ENEC expense and a $200 million annual increase for the recovery of the Companies’ February 28, 2023 ENEC under-recovery balances over three years, including debt and equity carrying costs. The second alternative is an $89 million annual increase in ENEC rates with the Companies securitizing approximately $1.9 billion of assets, including: (a) $553 million relating to ENEC under-recoveries as of February 28, 2023, (b) $88 million relating to major storm expense deferrals and (c) $1.2 billion relating to APCo’s West Virginia jurisdictional book values of the Amos and Mountaineer Plants and forecasted CCR and ELG investments at these generating facilities. The Companies continue to reflect ENEC under-recovery balances as current on their balance sheets since management cannot assert whether the WVPSC will approve recovery of ENEC under-recovery balances over a time frame different from the traditional one-year period.

Additionally, in April 2023, the Staff submitted the prudency review prepared by an independent consultant retained by the WVPSC staff of the Companies’ operation of the Amos, Mountaineer and Mitchell coal plants that Staff was directed to conduct by the WVPSC in May 2022 (Consultant’s Report). The Consultant’s Report states the opinion of the consultant that the Companies acted imprudently by not taking steps to achieve a 69% capacity factor at their coal-fired plants and recommends applying a disallowance factor of 52.9% to the Companies’ cumulative, September 30, 2022 ENEC under-recovery balance of approximately $430 million. The Consultant’s Report further states the consultant’s opinion that this disallowance factor could also be utilized in future ENEC filings. Adoption of the Consultant’s Report’s findings by the WVPSC could result in a disallowance of up to $285 million. The Companies disagree with the conclusions and recommendations contained in the Consultant’s Report and intend to dispute them in the appropriate proceedings before the WVPSC. In May 2023, the WVPSC established a procedural schedule for the 2021, 2022 and 2023 ENEC cases to begin in the third quarter of 2023, including APCo’s response to the independent consultant’s prudency review.

AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through June 30, 2023, AEP’s share of ETT’s cumulative revenues that are subject to review is approximately $1.6 billion. A base rate review could produce a refund 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 $1.6 billion of cumulative revenues above will be subject to review.

In April 2023, I&M received intervenor testimony in I&M’s 2021 PSCR Reconciliation for the 12-month period ending December 31, 2021 recommending disallowances of purchased power costs of $18 million associated with the OVEC Inter-Company Power Agreement (ICPA) and the AEGCo Unit Power Agreement (UPA) that were alleged to be above market in applying the MPSC’s Code of Conduct rules. Michigan staff submitted testimony in I&M’s 2021 PSCR Reconciliation with no recommended disallowances for PSCR costs incurred, including those associated with the OVEC ICPA and the AEGCo UPA. Michigan staff also recommended several options to address I&M’s shortfall in achieving Michigan’s annual one percent energy waste reduction savings level, resulting in potential future disallowed costs of up to approximately $14 million. In June 2023, Michigan staff submitted rebuttal testimony to update their calculation of the 2021 market proxy price resulting in a recommended disallowance of approximately $1 million related to the OVEC ICPA. An MPSC order on I&M’s 2021 PSCR Reconciliation is expected in the fourth quarter of 2023. If any PSCR costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In May 2023, KPCo filed an application seeking authority to defer, for future recovery, approximately $12 million of December 2022 purchased power costs not recoverable through its FAC. This requested deferral accounting authority would have enabled KPCo to pursue securitization of these costs. In June 2023, the KPSC denied KPCo’s request for deferral accounting authority.

Also in June 2023, following its order denying KPCo’s request for deferral accounting authority, 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.

KPCo is requesting a prudency determination and recovery mechanism for these costs in its 2023 base rate. Unless and until KPCo is granted a recovery mechanism for these purchased power costs from the KPSC it will impact cash flows and financial condition. Additionally, if any fines or penalties are levied against KPCo relating to the show cause order, it will 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. The filing proposes no changes in depreciation rates and an annual level of storm restoration expense in base rates of approximately $1 million. KPCo also proposed to discontinue tracking of PJM transmission costs through a rider, and to instead collect an annual level of costs through base rates. In addition, KPCo has proposed a rider to recover certain distribution reliability investments and related incremental operation and maintenance expenses. KPCo also requested a prudency determination and recovery mechanism for approximately $16 million of purchased power costs not recoverable through its FAC since its last base case.

In conjunction with its June 2023 filing, KPCo further requested to finance, through the issuance of securitization bonds, approximately $471 million of regulatory assets recorded as of June 2023 including: (a) $289 million of plant retirement costs, (b) $79 million of deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, (c) $52 million of deferred purchased power expenses and (d) $51 million of under-recovered purchased power rider costs. Plant retirement costs and deferred purchased power expenses have been deemed prudent in prior KPSC decisions. KPCo has requested a prudency determination for the deferred storm costs and under-recovered purchase power rider costs since the last base case in this proceeding. Consistent with Kentucky statutory requirements, the present value of the return on accumulated deferred income tax benefits related to plant retirement costs and deferred purchase power expenses were proposed to reduce the amount authorized to be financed through securitization.

In December 2021, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2018-2019 audit period were imprudent and should be disallowed. In May 2022, intervenors filed for rehearing on the 2016-2017 OVEC cost recovery audit period claiming the PUCO’s April 2022 order to adopt the findings of the audit report were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In June 2022, the PUCO granted rehearing on the 2016-2017 audit period for purposes of further consideration. Management disagrees with these claims and is unable to predict the impact of these disputes, however, if any costs are disallowed or refunds are ordered it could reduce future net income and cash flows and impact financial condition. See "OVEC" section of Note 17 in the 2022 Annual Report for additional information on AEP and OPCo’s investment in OVEC.

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 Distribution Investment Rider, 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. Staff testimony and a hearing is expected in the third quarter of 2023. If OPCo is ultimately not permitted to fully collect its ESP rates it could reduce future net income and cash flows and impact financial condition.

In November 2022, PSO filed a request with the OCC for a $173 million annual increase in rates based upon a 10.4% ROE with a capital structure of 45.4% debt and 54.6% common equity, net of existing rider revenues and certain incremental renewable facility benefits expected to be provided to customers through riders. The requested annual revenue increase includes a $47 million annual depreciation expense increase related to the accelerated depreciation recovery of the Northeastern Plant, Unit 3 through 2026, and a $16 million annual amortization expense increase to recover intangible plant over a 5-year useful life instead of a 10-year useful life. PSO’s request also includes recovery of the 154 MW Rock Falls Wind Facility through base rates to aid PSO’s near-term capacity needs and support compliance with SPP’s 2023 increased capacity planning reserve margin requirements. In November 2022, PSO entered into an agreement to acquire the Rock Falls Wind Facility. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. PSO closed on the acquisition and placed the Rock Falls Wind Facility in-service on March 31, 2023. In addition, PSO requested an annual formula based rate tariff, with an initial one-year pilot term. In the event the requested formula based rate tariff is denied, PSO has requested an expanded rider to recover certain distribution investments and related expenses as well as an expanded transmission cost recovery rider.

In March 2023, OCC staff and various intervenors filed testimony supporting net annual revenue changes ranging from a $42 million net decrease to a $49 million net increase based upon ROEs ranging from 8.6% to 9.5%. The difference between PSO’s request and OCC staff and intervenor testimony is primarily due to: (a) rejection of PSO’s request to accelerate the recovery of Northeastern Plant, Unit 3 from its original retirement date of 2040 to its projected retirement date of 2026, (b) rejection of PSO’s request to recover intangible plant over a 5-year useful life instead of a 10-year useful life, (c) recommended disallowance of approximately $9 million in certain distribution plant investments, (d) opposition to inclusion of the Rock Falls Wind Facility revenue requirement in customer rates before PSO’s next base rate case, (e) opposition to PSO’s inclusion of its deferred tax asset associated with net operating loss on a stand-alone tax basis in rate base and (f) lower recommended ROEs and recommendations to use certain hypothetical capital structures. Parties also recommended that the OCC reject PSO’s requested formula based rate, and alternate requests for expanded distribution investment and transmission cost recovery riders.

In May 2023, PSO, OCC staff and certain intervenors filed a contested joint stipulation and settlement agreement with the OCC that includes an annual revenue increase of $50 million, based upon a 9.5% ROE with a capital structure of 45.4% debt and 54.6% common equity, net of existing rider revenues and certain incremental renewable facility benefits expected to be provided to customers through riders. The net annual increase includes recovery of the 154 MW Rock Falls Wind Facility through base rates. Northeastern Plant, Unit 3 will continue to be recovered through 2040 and intangible plant will continue to be recovered over a 10-year useful life. The agreement also provides for certain rider-related items, including: (a) revision to PSO’s Fuel Clause Adjustment Rider to reflect factor updates to occur on a semi-annual basis, (b) approval to defer a weighted average cost of capital carrying charge on PSO’s deferred tax asset associated with net operating loss on a stand-alone tax basis to a regulatory asset and, contingent upon receipt of a supportive private letter ruling from the IRS, approval to collect the deferral through a rider over a 20-month period, and (c) approval to implement an expanded rider to recover certain distribution investments for a three-year term, up to a $6 million annual revenue requirement.

In May 2023, a hearing on the merits of the contested joint stipulation and settlement agreement was held at the OCC and PSO implemented an interim annual base rate increase, subject to refund, based upon the contested joint stipulation and settlement agreement. Through June 30, 2023, PSO’s cumulative revenue from the interim annual base rate increase, subject to refund, is approximately $16 million. In July 2023, an ALJ report was filed and included recommendations generally consistent with the intervenor testimony. The ALJ report is not binding on the OCC. A final order is expected in the third quarter of 2023. If PSO is required to refund any of the $16 million of revenue recorded subject to refund or any costs are not recoverable, it would 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.

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

In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. 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.

Management does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of June 30, 2023. However, if SWEPCo is ultimately unable to recover AFUDC in excess of the Texas jurisdictional capital cost cap, it would be expected to result in a pretax net disallowance ranging from $80 million to $90 million. In addition, if SWEPCo is ultimately unable to recover AFUDC in excess of the Texas jurisdictional cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $195 million related to revenues collected from February 2013 through June 2023 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.

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 ROE of 9.6%, 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. The appeal will move forward following the conclusion of the 2012 Texas Base Rate Case. 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 a judicial review of the several errors challenged in the PUCT’s final order.

In December 2020, SWEPCo filed a request with the LPSC for a $134 million annual increase in Louisiana base rates based upon a proposed 10.35% ROE. SWEPCo’s requested annual increase includes accelerated depreciation related to the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which were or are expected to be retired early. SWEPCo also included recovery of Welsh Plant, Unit 2 over the blended useful life of Welsh Plant, Units 1 and 3. SWEPCo subsequently revised the requested annual increase to $95 million to reflect removing hurricane storm restoration costs from the base case filing, to modify the proposed recovery of the Dolet Hills Power Station and revisions to various proposed amortizations. The hurricane costs have been requested in a separate storm filing. See “2021 Louisiana Storm Cost Filing” below for more information.

In January 2023, the LPSC approved a settlement which provides for an annual revenue increase of $27 million based upon a 9.5% ROE and includes: (a) a $21 million increase in base rates effective February 2023, (b) a $14 million rider to recover costs of the Dolet Hills Power Station and Pirkey Plant including a return, (c) an $8 million reduction in fuel rates, (d) an adoption of a 3-year formula rate term subject to an earnings band and (e) the recovery of certain incremental SPP charges net of associated revenue and the Louisiana jurisdictional share of the return on and of projected transmission capital investment outside of the earnings band. The settlement agreement did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which is being addressed in a separate proceeding.

The primary differences between SWEPCo’s requested annual rate increase and the agreed upon settlement increase are primarily due to: (a) a reduction in the requested ROE, (b) recovery of the Dolet Hills Power Station and Pirkey Plant over ten years in a separate rider mechanism as opposed to base rates with accelerated depreciation rates, (c) maintaining existing depreciation rates for Welsh Plant, Units 1 and 3 and (d) the severing of SWEPCo’s proposed adjustment to include a stand-alone NOLC deferred tax asset in rate base. In January 2023, a hearing was held related to the inclusion of a stand-alone NOLC deferred tax asset in rate base and an order from the LPSC is expected in 2023.

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% until the recovery mechanism is determined in phase two of this proceeding. SWEPCo will submit additional information in phase two of this proceeding to determine whether securitization of the costs is more cost effective than recovery through typical ratemaking. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement.

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:

(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.

In May 2021, certain joint customers submitted a formal challenge at the FERC related to the 2020 Annual Update of the 2019 SPP Transmission Formula Rates of the AEP transmission owning subsidiaries within SPP. In March 2022, the FERC issued an order on the formal challenge which ruled in favor of the joint customers on several issues. Management has determined that the result of the order had an immaterial impact to the financial statements of AEP, AEPTCo, PSO and SWEPCo. In November 2022, certain joint customers appealed the FERC decision to the U.S. Court of Appeals for the District of Columbia Circuit.

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. The PAPUC decision remains subject to the jurisdiction and review of the United States District Court for the Middle District of Pennsylvania, which had stayed review of the PAPUC decision until the Pennsylvania state court had ordered. The procedural schedule for this case states that a decision by the United States District Court for the Middle of Pennsylvania will not be reached until the second half of 2023.

In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. PJM continues to evaluate reliability and market efficiency in the area. As of June 30, 2023, AEP’s share of IEC capital expenditures was approximately $90 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 February 2022, the OCC filed a complaint against AEPSC, American Transmission Systems, Inc. and Duke Energy Ohio, alleging the 50 basis point RTO incentive included in Ohio Transmission Owners’ respective transmission formula rates is not just and reasonable and therefore should be eliminated on the basis that RTO participation is not voluntary, but rather is required by Ohio law. In March 2022, AEPSC filed a motion to dismiss the OCC’s February 2022 complaint with the FERC on the basis of certain deficiencies, including that the complaint fails to request relief that can be granted under FERC regulations because AEPSC is not a public utility nor does it have a transmission rate on file with the FERC. In December 2022, the FERC issued an order removing the 50 basis point RTO incentive from OPCo and OHTCo transmission formula rates effective the date of the February 2022 complaint filing and directed OPCo and OHTCo to provide refunds, with interest, within sixty days of the date of its order. In January 2023, both AEPSC and the OCC filed requests for rehearing with the FERC. In February 2023, in compliance with the FERC’s December 2022 order, AEPSC submitted a filing to the FERC to update OPCo and OHTCo 2023 transmission formula rates to exclude the 50 basis point RTO incentive and provide refunds with interest. In April 2023, the FERC approved the updated transmission formula rates for OPCo and OHTCo and issued an Order on Rehearing affirming its February 2022 decision. This decision has been appealed to the U.S. Court of Appeals for the Sixth Circuit. Management expects the December 2022 FERC order to reduce AEP’s pretax income by approximately $20 million on an annual basis.

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 AEGCo’s unit power agreement with 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. The FERC established a separate proceeding to review: (a) AEGCo’s acquisition value for the Rockport Plant, Unit 2 base generating asset (original cost and accumulated depreciation), (b) the appropriateness of including future capital additions as stated components in proposed depreciation rates, in light of the Unit Power Agreement’s formula rate mechanism, (c) the appropriateness of applying two different depreciation rates to a single asset common to both units and (d) the accounting and regulatory treatment of Rockport Plant, Unit 2 costs of removal and related AROs. It is expected that the FERC will issue an order on this review in the second half of 2023. This FERC review and subsequent order on these issues could reduce future net income and cash flows and impact financial condition.

In March 2023 and May 2023, certain joint customers submitted a complaint and a formal challenge at the FERC related to the 2022 Annual Update of the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP, respectively. These challenges primarily relate to stand-alone treatment of NOLCs in the transmission formula rates of the AEP transmission owning subsidiaries. AEPSC, on behalf of the AEP transmission owning subsidiaries within PJM and SPP, filed answers to the joint formal challenge and complaint with the FERC in the second quarter of 2023.