As discussed in the 2021 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2021 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 2022 and updates the 2021 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.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets are not deemed recoverable, it could materially reduce future net income and cash flows and impact financial condition.

In April 2016, Welsh Plant, Unit 2 was retired. As part of the 2016 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of Welsh Plant, Unit 2, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $7 million in 2017. See “2016 Texas Base Rate Case” section below for additional information. As part of the 2019 Arkansas Base Rate Case, SWEPCo received approval from the APSC to recover the Arkansas jurisdictional share of Welsh Plant, Unit 2. In December 2020, SWEPCo filed a request with the LPSC to recover the Louisiana jurisdictional share of Welsh Plant, Unit 2. See “2020 Louisiana Base Rate Case” section below for additional information. As of March 31, 2022, SWEPCo had a regulatory asset for plant retirement costs pending approval recorded on its balance sheet of $35 million related to the Louisiana jurisdictional share of Welsh Plant, Unit 2.

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, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in 2021. SWEPCo has also requested recovery of the Dolet Hills Power Station in the Arkansas and Louisiana jurisdictions through base rate cases. See “2020 Texas Base Rate Case”, “2020 Louisiana Base Rate Case” and “2021 Arkansas Base Rate Case” sections below for additional information. The Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Arkansas and Texas jurisdictions. As of March 31, 2022, SWEPCo had a regulatory asset for the Dolet Hills Power Station pending approval recorded on its balance sheet of $72 million related to the Arkansas and Louisiana jurisdictional shares.

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.


Plant	Net Book Value		Accelerated Depreciation Regulatory Asset		Cost of Removal Regulatory Liability			Projected Retirement Date	Current Authorized Recovery Period	Annual Depreciation (a)
	(dollars in millions)
Northeastern Plant, Unit 3	$	159.1	$	132.5	$	20.1	(b)	2026	(c)	$	14.9
Pirkey Power Plant	99.6		107.7		39.3			2023	(d)	13.4
Welsh Plant, Units 1 and 3	467.2		55.7		58.6		(e)	2028	(f)	37.3

In December 2021, the Dolet Hills Power Station was retired. The Dolet Hills Power Station non-fuel costs are recoverable by SWEPCo through base rates and through a rate rider in the Texas jurisdiction. As of March 31, 2022, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $108 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. As of March 31, 2022, SWEPCo had a net under-recovered fuel balance of $84 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Dolet Hills Power Station. Additional reclamation and other land-related costs incurred by DHLC and Oxbow will be billed to SWEPCo and included in existing fuel clauses.

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $30 million of additional costs with a recovery period to be determined at a later date. In November 2021, the LPSC issued a directive which deferred the issues regarding modification of the level and timing of recovery of the Dolet Hills Power Station from SWEPCo’s pending rate case to a separate existing docket. In addition, the recovery of the deferred fuel costs are planned to be addressed.

In 2020, management announced plans to retire the Pirkey Power Plant in 2023. The Pirkey Power Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses. As of March 31, 2022, SWEPCo’s share of the net investment in the Pirkey Power Plant was $207 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Power Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and operating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $87 million as of March 31, 2022. As of March 31, 2022, SWEPCo had a net under-recovered fuel balance of $84 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Pirkey Power Plant. Additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


	AEP
	March 31,		December 31,
	2022		2021
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs (a)	$	236.8	$	430.2
Pirkey Power Plant Accelerated Depreciation	107.7		87.0
Dolet Hills Power Station Accelerated Depreciation	72.2		72.3

Welsh Plant, Units 1 and 3 Accelerated Depreciation	55.7		45.9
Plant Retirement Costs – Unrecovered Plant, Louisiana	35.2		35.2


Dolet Hills Power Station Fuel Costs - Louisiana	31.3		30.9
Other Regulatory Assets Pending Final Regulatory Approval	10.5		9.2
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	279.6		256.9
Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		25.9
COVID-19	11.9		11.2




Other Regulatory Assets Pending Final Regulatory Approval	46.1		43.9
Total Regulatory Assets Pending Final Regulatory Approval	$	912.9	$	1,048.6


	AEP Texas
	March 31,		December 31,
	2022		2021
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Mobile Generation Lease Payments	$	1.3	$	—
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	23.6		22.4
Vegetation Management Program	5.2		5.2
Texas Retail Electric Provider Bad Debt Expense	4.1		4.1
COVID-19	3.6		2.1
Other Regulatory Assets Pending Final Regulatory Approval	8.0		7.4
Total Regulatory Assets Pending Final Regulatory Approval	$	45.8	$	41.2


	APCo
	March 31,		December 31,
	2022		2021
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
COVID-19 – Virginia	$	6.8	$	6.8

Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	75.2		68.8
Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		25.9


Other Regulatory Assets Pending Final Regulatory Approval	5.0		3.6
Total Regulatory Assets Pending Final Regulatory Approval	$	112.9	$	105.1


	I&M
	March 31,		December 31,
	2022		2021
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
COVID-19	0.2		1.7


Other Regulatory Assets Pending Final Regulatory Approval	0.8		1.9
Total Regulatory Assets Pending Final Regulatory Approval	$	1.1	$	3.7


	SWEPCo
	March 31,		December 31,
	2022		2021
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs (a)	$	236.8	$	430.2
Pirkey Power Plant Accelerated Depreciation	107.7		87.0
Dolet Hills Power Station Accelerated Depreciation	72.2		72.3
Welsh Plant, Units 1 and 3 Accelerated Depreciation	55.7		45.9
Plant Retirement Costs – Unrecovered Plant, Louisiana	35.2		35.2
Dolet Hills Power Station Fuel Costs- Louisiana	31.3		30.9
Other Regulatory Assets Pending Final Regulatory Approval	2.3		2.4
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	151.2		148.0
Asset Retirement Obligation - Louisiana	10.6		10.3



Other Regulatory Assets Pending Final Regulatory Approval	20.0		18.4
Total Regulatory Assets Pending Final Regulatory Approval	$	723.0	$	880.6

Through March 31, 2022, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is approximately $368 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 November 2020, the Virginia SCC issued an order on APCo’s 2017-2019 Triennial Review filing concluding that APCo earned above its authorized ROE but within its ROE band for the 2017-2019 period, resulting in no refund to customers and no change to APCo base rates on a prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's 2020-2022 triennial review period with the continuation of a 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top).

In December 2020, an intervenor filed a petition at the Virginia SCC requesting reconsideration of: (a) the failure of the Virginia SCC to apply a threshold earnings test to the approved regulatory asset for APCo’s closed coal-fired generation assets and (b) the Virginia SCC’s use of a 2011 benchmark study to measure the replacement value of capacity for purposes of APCo’s 2017 – 2019 earnings test.

In December 2020, APCo filed a petition at the Virginia SCC requesting reconsideration of: (a) certain issues related to APCo’s going-forward rates and (b) the Virginia SCC’s decision to deny APCo tariff changes that align rates with underlying costs. For APCo’s going-forward rates, APCo requested that the Virginia SCC clarify its final order and clarify whether APCo’s current rates will allow it to earn a fair return. If the Virginia SCC’s order did conclude that APCo was able to earn a fair return through existing base rates, APCo further requested that the Virginia SCC clarify whether it has the authority to also permit an increase in base rates.

In March 2021, an intervenor filed its appeal with the Virginia Supreme Court related to the November 2020 order in which it stated the Virginia SCC erred: (a) in determining that Virginia law did not apply to its determination to permit amortization for recovery of costs associated with retired coal-fired generation assets, (b) in establishing a new regulatory asset for a cost incurred outside of the triennial review period due to its failure to apply a threshold earnings test before approving deferred cost recovery and (c) in misapplying the requirement that APCo bear the burden of demonstrating that power purchases made by APCo from its affiliate, OVEC, were priced at the lower of OVEC’s cost or the market price for nonaffiliated power.

In March 2021, APCo filed its appeal with the Virginia Supreme Court related to the November 2020 order in which it stated the Virginia SCC erred: (a) in finding that costs associated with asset impairments related to early retirement determinations made by APCo for certain generation facilities should not be attributed to the test periods under review and deemed fully recovered in the period recorded, (b) in finding that it was permitted to evaluate the reasonableness of APCo’s decision to record, per books for financial reporting purposes, asset impairments related to early retirement determinations for certain generation facilities, (c) as a result of the errors described in (a) and (b), in denying APCo an increase in rates, (d) in failing to review and make any findings regarding whether APCo’s rates would allow it to earn a fair rate of return going forward, (e) in denying APCo an increase in base rates by

failing to ensure that APCo has an opportunity to recover its costs and earn a fair rate of return, thereby resulting in a taking of private property for public use without just compensation and (f) in retroactively adjusting APCo’s depreciation expense for purposes of calculating APCo’s earnings for the 2017-2019 triennial period.

In March 2021, the Virginia SCC issued an order confirming certain decisions from the November 2020 order and rejecting the various requests for reconsideration from APCo and an intervenor. In March 2021, APCo filed a notice of appeal of the reconsideration order with the Virginia Supreme Court. In September 2021, APCo submitted its brief before the Virginia Supreme Court. The brief was in alignment with the previous items of appeal filed by APCo in March 2021. In October 2021, the Virginia SCC and additional intervenors filed briefs with the Virginia Supreme Court disagreeing with the items appealed by APCo in the Triennial Review decision. Additionally, the Virginia SCC and APCo filed briefs disagreeing with the items appealed by an intervenor in a separate appeal of the same decision. In March 2022, oral arguments were held at the Virginia Supreme Court and APCo is currently awaiting the Virginia Supreme Court’s decision.

APCo ultimately seeks an increase in base rates through its appeal to the Virginia Supreme Court. Among other issues, this appeal includes APCo’s request for proper treatment of the closed coal-fired plant assets in APCo’s 2017-2019 triennial period, reducing APCo’s earnings below the bottom of its authorized ROE band. If APCo’s appeal regarding treatment of the closed coal plants is granted by the Virginia Supreme Court, it could initially reduce future net income and impact financial condition as a consequence of expensing the closed coal-fired plant regulatory asset established as a result of the Virginia SCC’s decision in the 2017-2019 Triennial Review. A Virginia Supreme Court decision in favor of APCo’s original expensing of the closed coal-fired plant asset balances would likely result in a remand to the Virginia SCC. Upon a subsequent Virginia SCC order, the initial negative impact for the write-off of the closed coal-fired plant asset balances could potentially be offset by an increase in base rates for earning below APCo’s 2017-2019 authorized ROE band.

In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting approvals necessary to implement CCR/ELG compliance plans at the Amos and Mountaineer Plants. Intervenors in Virginia and West Virginia recommended that only the CCR-related investments be constructed at Amos and Mountaineer and, as a consequence, that APCo close these generating facilities at the end of 2028.

In August 2021, the Virginia SCC issued an order approving APCo’s request to construct CCR-related investments at the Amos and Mountaineer Plants and approved recovery of CCR-related other operation and maintenance expenses and investments through an active rider. The order denied APCo’s request to construct the ELG investments and denied recovery of previously incurred ELG costs. In March 2022, APCo refiled for approval of the ELG investments and previously incurred ELG costs. A hearing is scheduled to take place in September 2022 and an order is anticipated in the fourth quarter of 2022.

Also in August 2021, the WVPSC approved the request to construct CCR/ELG investments at the Amos and Mountaineer Plants and approved recovery of the West Virginia jurisdictional share of these costs through an active rider. In October 2021, due to the Virginia SCC previously rejecting the ELG investments, the WVPSC issued an order directing APCo to proceed with CCR/ELG compliance plans that would allow the plants to continue operating beyond 2028. The October order further states that APCo will not share capacity and energy from the plants with customers from Virginia if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plants to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that APCo will be given the opportunity to recover, from West Virginia customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plants beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. In October and November 2021, intervenors filed petitions for reconsideration at the WVPSC requesting clarification on certain aspects of the order, primarily the jurisdictional allocation of future operating expenses and plant costs.

APCo expects total Amos and Mountaineer Plant ELG investment, excluding AFUDC, to be approximately $197 million. As of March 31, 2022, APCo’s Virginia jurisdictional share of the net book value, before cost of removal including CWIP and inventory, of the Amos and Mountaineer Plants was approximately $1.5 billion and APCo’s Virginia jurisdictional share of its ELG investment balance in CWIP for these plants was $41 million.

In April 2021, APCo and WPCo (the Companies) requested a $73 million annual increase in ENEC rates based on a cumulative combined $55 million ENEC under-recovery as of February 28, 2021 and a combined $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 modifying the original $48 million reduction to a $17 million reduction related to 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 projections related to 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. It is anticipated that the WVPSC will issue an order on the reopened 2021 ENEC filing in the second quarter of 2022.

In April 2022, the Companies submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, inclusive of the previously requested $155 million increase, effective September 1, 2022. As of March 31, 2022, the Companies’ cumulative ENEC under-recovery was $243 million. If any deferred ENEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through March 31, 2022, AEP’s share of ETT’s cumulative revenues that are subject to review is approximately $1.4 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, 2023, during which the $1.4 billion of cumulative revenues above will be subject to review.

In April 2022, an Administrative Law Judge (ALJ) issued a Proposal for Decision (PFD) for I&M’s PSCR reconciliation for the 12-month period ending December 31, 2020, recommending the MPSC disallow approximately $8 million of purchased power costs that I&M incurred under the Inter-Company Power Agreement with OVEC and the Unit Power Agreement with AEGCo. Management disagrees with the ALJ’s recommended cost disallowances and intends to file exceptions to the PFD. I&M anticipates that the MPSC will issue a final decision in the second half of 2022. Management is unable to predict the impact, if any, that the MPSC’s final decision may have on future results of operations, financial condition and cash flows.

KPCo and WPCo each own a 50% interest in the Mitchell Plant. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.

In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that would allow the plant to continue operating beyond 2028. The WVPSC’s order further states WPCo will not share capacity and energy from the plant with KPCo customers if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plant to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. In October and November 2021, intervenors filed petitions for reconsideration at the WVPSC requesting clarification on certain aspects of the

In November 2021, AEP made filings with the KPSC, WVPSC and FERC seeking approval of a proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo pursuant to which WPCo would replace KPCo as the operator of the Mitchell Plant. In February 2022, AEP filed a motion to withdraw its filing with the FERC, noting that AEP intends to re-file its request after the KPSC and WVPSC have reviewed the agreements. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.

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. Management disagrees with these claims and is unable to predict the impact, if any, these disputes may have on future results of operations, financial condition and cash flows. See "OVEC" section of Note 17 in the 2021 Annual Report for additional information on AEP and OPCo’s investment in OVEC.

In February 2021, severe winter weather had a significant impact in SPP, resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply 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, PSO’s natural gas expenses and purchases of electricity still to be recovered from customers are $681 million as of March 31, 2022.

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchases of electricity, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. In January 2022, PSO, OCC staff and certain intervenors filed a joint stipulation and settlement agreement with the OCC to approve PSO’s securitization of the extraordinary fuel and purchases of electricity. The agreement includes a determination that all of PSO’s extraordinary fuel and purchases of electricity were prudent and reasonable and a 0.75% carrying charge, subject to true-up based on actual financing costs. In February 2022, the OCC approved the joint stipulation and settlement agreement in its financing order. The issuance of the securitization bonds must be approved by the Supreme Court of Oklahoma. A ruling by the Supreme Court is expected in the second quarter of 2022. PSO expects to complete the securitization process in 2022, subject to market conditions.

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 July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. No parties filed a motion for rehearing with the Texas Supreme Court. 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 disagrees with the Court of Appeals decision and submitted a Petition for Review with the Texas Supreme Court in November 2021. The Texas Supreme Court has requested responses to the Petition for Review, which are due at the end of April 2022.

If SWEPCo is ultimately unable to recover capitalized Turk Plant costs, including 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 AFUDC is ultimately determined to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $180 million related to revenues collected from February 2013 through March 2022 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. 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. The proposed net annual increase: (a) includes $5 million related to vegetation management to maintain and improve the reliability of SWEPCo’s Texas jurisdictional distribution system, (b) requests a $10 million annual depreciation increase and (c) seeks $2 million annually to establish a storm catastrophe reserve. In addition, SWEPCo also requested recovery of the Texas jurisdictional share of the Dolet Hills Power Station of $45 million which was retired in December 2021. 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 that would 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 would 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 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 subsequently revised the requested annual increase to $114 million to reflect removing hurricane storm restoration costs from the base case filing. The hurricane costs have been requested in a separate storm filing. See “2021 Louisiana Storm Cost Filing” below for more information. The base case filing would extend the formula rate plan for five years and includes modifications to the formula rate plan to allow for forward-looking transmission costs, reflects the impact of net operating losses associated with the acceleration of certain tax benefits and incorporates future federal corporate income tax changes. The proposed net annual increase requests a $32 million annual depreciation increase to recover Louisiana’s share of the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which are expected to be retired early.

In July 2021, the LPSC staff filed testimony supporting a $6 million annual increase in base rates based upon a ROE of 9.1% while other intervenors recommended a ROE ranging from 9.35% to 9.8%. The primary differences between SWEPCo’s requested annual increase in base rates and the LPSC staff’s recommendation include: (a) a reduction in depreciation expense, (b) recovery of Dolet Hills Power Station and Pirkey Power Plant in a separate rider mechanism, (c) the rejection of SWEPCo’s proposed adjustment to include a stand-alone net operating loss carryforward deferred tax asset in rate base and (d) a reduction in the proposed ROE.

In September 2021, SWEPCo filed rebuttal testimony supporting a revised requested annual increase in base rates of $95 million. The primary differences in the rebuttal testimony from the previous revised request of $114 million are modifications to the proposed recovery of the Dolet Hills Power Station and revisions to various proposed amortizations. LPSC staff and intervenor responses to SWEPCo’s rebuttal testimony were filed in October 2021. The procedural schedule for the case is on hold due to ongoing settlement discussions.

In July 2021, SWEPCo filed a request with the APSC for an $85 million annual increase in Arkansas base rates based upon a proposed 10.35% ROE with a capital structure of 48.7% debt and 51.3% common equity. The proposed annual increase includes: (a) a $41 million revenue requirement for the North Central Wind Facilities, (b) a $14 million annual depreciation increase primarily due to recovery of the Dolet Hills Power Station through 2026 and Pirkey Plant and Welsh Plant, Units 1 and 3 through 2037 and (c) a $6 million increase due to SPP costs. SWEPCo requested that rates become effective in June 2022.

APSC staff filed testimony supporting a $47 million annual increase in base rates based upon a ROE of 9.3% while other intervenors recommended a ROE ranging from 8.75% to 9.25%. The primary differences between SWEPCo’s requested annual increase in base rates and the APSC staff’s recommendation include: (a) recovery of the Dolet Hills Power Station through 2046 with no debt or equity return, (b) a reduction in the proposed ROE with a capital structure of 55.5% debt and 44.5% common equity and (c) lower depreciation rates. The APSC staff also recommended future generating facility retirements be treated similar to the Dolet Hills Power Station recommendation of recovery with no debt or equity return. Also, an intervenor recommended no debt or equity return on the Pirkey Power Plant after its retirement, which is currently expected to be in 2023. SWEPCo filed rebuttal testimony in January 2022 revising the requested annual increase in Arkansas base rates to $81 million with

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 October 2021, SWEPCo filed a request with the LPSC for recovery of $145 million in deferred storm costs associated with the three storms. As part of the filing, SWEPCo requested recovery of the carrying charges on the deferred regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. LPSC staff testimony is due to the LPSC in May 2022 and an order is expected before the end of 2022. If any of the storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

As discussed in the “PSO Rate Matters” section above, 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 $418 million as of March 31, 2022, of which $96 million, $141 million and $181 million is related to the Arkansas, Louisiana and Texas jurisdictions, respectively.

In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Subsequently, SWEPCo began recovery of these fuel costs. SWEPCo is currently recovering the fuel costs at an interim carrying charge of 0.3%. In April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05%, which has been supported by APSC staff. Various other parties have recommended recovery periods ranging from 5-20 years with a carrying charge of 1.65%. SWEPCo is awaiting a decision from the APSC. The prudence of these fuel costs is expected to be addressed in a separate proceeding.

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 of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application requested a five-year recovery with a carrying charge of 7.18%. In March 2022, the PUCT ordered SWEPCo to recover the Texas jurisdictional share of the fuel costs over five years with a carrying charge of 1.65% and ordered SWEPCo to file a fuel reconciliation addressing fuel costs from January 1, 2020 through December 31, 2021.

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 will have an immaterial impact to the financial statements of AEP, AEPTCo, PSO and SWEPCo.

In 2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan to alleviate congestion. Transource Energy owns 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 has appealed the PAPUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. The case before the state court is pending and the case before the United States District Court for the Middle District of Pennsylvania is currently suspended, pending the outcome of the case in the Pennsylvania state court.

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. PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. As of March 31, 2022, AEP’s share of IEC capital expenditures was approximately $82 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 Office of the Ohio Consumer’s Council 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 Ohio Consumer’s Council 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. Management believes its financial statements adequately address the impact of the February 2022 complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.