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 September 30, 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. 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 over five years, 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. SWEPCo has requested recovery of the Dolet Hills Power Station in the Louisiana jurisdiction through the 2020 Louisiana Base Rate Case. As of September 30, 2022, SWEPCo had a regulatory asset of $55 million, pending approval, recorded on its balance sheet related to the Louisiana and FERC jurisdictional shares of the Dolet Hills Power Station. The Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction, through 2027 in the Arkansas jurisdiction and through 2046 in the Texas jurisdiction. See “2020 Texas Base Rate Case”, “2020 Louisiana Base Rate Case” and “2021 Arkansas Base Rate Case” sections below for additional information.

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	$	143.7	$	141.4	$	20.2	(b)	2026	(c)	$	14.9
Pirkey Plant	65.0		150.7		39.6			2023	(d)	12.5
Welsh Plant, Units 1 and 3	432.3		75.7		58.2		(e)	2028	(f)	39.8

In 2020, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining. 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 a combination of base rates and rate riders. As of September 30, 2022, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $113 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, 2022, SWEPCo had a net under-recovered fuel balance of $236 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 $30 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 $30 million deferral, with refunds to customers over five years. In September 2022, SWEPCO filed rebuttal testimony addressing the LPSC staff recommendations.

In 2020, management announced plans to retire the Pirkey Plant in 2023. The Pirkey Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of September 30, 2022, SWEPCo’s share of the net investment in the Pirkey Plant was $216 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey 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 $49 million as of September 30, 2022. As of September 30, 2022, SWEPCo had a net under-recovered fuel balance of $236 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Upon cessation of lignite deliveries by Sabine to the Pirkey 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
	September 30,		December 31,
	2022		2021
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Pirkey Plant Accelerated Depreciation	$	150.7	$	87.0
Unrecovered Winter Storm Fuel Costs (a)	126.1		430.2

Welsh Plant, Units 1 and 3 Accelerated Depreciation	75.7		45.9
Dolet Hills Power Station Accelerated Depreciation	54.7		72.3

Plant Retirement Costs – Unrecovered Plant, Louisiana	35.2		35.2


Dolet Hills Power Station Fuel Costs - Louisiana	31.8		30.9
Other Regulatory Assets Pending Final Regulatory Approval	21.2		9.2
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	306.5		241.8
2017-2019 Virginia Triennial Under-Earnings	37.0		—
Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		25.9
2020-2022 Virginia Triennial Under-Earnings	25.3		15.1
COVID-19	8.7		11.2
Renewable Energy Portfolio Standards Costs - Virginia	—		2.1





Other Regulatory Assets Pending Final Regulatory Approval	42.4		41.8
Total Regulatory Assets Pending Final Regulatory Approval	$	941.2	$	1,048.6


	AEP Texas
	September 30,		December 31,
	2022		2021
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Mobile Generation Lease Payments	$	9.2	$	—
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	27.0		22.4
Vegetation Management Program	5.2		5.2
Texas Retail Electric Provider Bad Debt Expense	4.1		4.1
COVID-19	3.8		2.1
Other Regulatory Assets Pending Final Regulatory Approval	8.2		7.4
Total Regulatory Assets Pending Final Regulatory Approval	$	57.5	$	41.2


	APCo
	September 30,		December 31,
	2022		2021
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
COVID-19 – Virginia	$	7.0	$	6.8

Regulatory Assets Currently Not Earning a Return
Storm-Related Costs - West Virginia	69.9		53.7
2017-2019 Virginia Triennial Under-Earnings	37.0		—
Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		25.9
2020-2022 Virginia Triennial Under-Earnings	25.3		15.1


Renewable Energy Portfolio Standards Costs - Virginia	—		2.1

Other Regulatory Assets Pending Final Regulatory Approval	1.6		1.5
Total Regulatory Assets Pending Final Regulatory Approval	$	166.7	$	105.1


	I&M
	September 30,		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	0.1		1.7


Other Regulatory Assets Pending Final Regulatory Approval	1.7		1.9
Total Regulatory Assets Pending Final Regulatory Approval	$	1.9	$	3.7


	OPCo
	September 30,		December 31,
	2022		2021
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Not Earning a Return



Storm-Related Costs	$	32.5	$	3.8

Other Regulatory Assets Pending Final Regulatory Approval	0.1		—
Total Regulatory Assets Pending Final Regulatory Approval	$	32.6	$	3.8


	PSO
	September 30,		December 31,
	2022		2021
Noncurrent Regulatory Assets	(in millions)





Regulatory Assets Currently Not Earning a Return


Storm-Related Costs	$	24.3	$	13.9
Other Regulatory Assets Pending Final Regulatory Approval	0.1		0.3
Total Regulatory Assets Pending Final Regulatory Approval	$	24.4	$	14.2


	SWEPCo
	September 30,		December 31,
	2022		2021
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Pirkey Plant Accelerated Depreciation	$	150.7	$	87.0
Unrecovered Winter Storm Fuel Costs (a)	126.1		430.2

Welsh Plant, Units 1 and 3 Accelerated Depreciation	75.7		45.9
Dolet Hills Power Station Accelerated Depreciation	54.7		72.3
Plant Retirement Costs – Unrecovered Plant, Louisiana	35.2		35.2
Dolet Hills Power Station Fuel Costs- Louisiana	31.8		30.9
Other Regulatory Assets Pending Final Regulatory Approval	4.9		2.4
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	151.3		148.0
Asset Retirement Obligation - Louisiana	11.3		10.3



Other Regulatory Assets Pending Final Regulatory Approval	14.9		18.4
Total Regulatory Assets Pending Final Regulatory Approval	$	656.6	$	880.6

Through September 30, 2022, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is approximately $524 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 March 2021, APCo filed an 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 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.

In August 2022, the Virginia Supreme Court issued its opinion on submitted appeals of APCo’s 2017-2019 Virginia Triennial Review concluding that the Virginia SCC: a) erred in finding it was not reasonable for APCo to record all remaining costs associated with early retirement of certain coal-fired generating plants in the 2017-2019 earnings test period, b) did not err by ordering APCo to retroactively implement depreciation rates for the years 2018 and 2019 and c) did not err in finding that APCo’s affiliate costs from OVEC were reasonable. The Virginia Supreme Court then remanded the issue regarding the retired coal-fired plants back to the Virginia SCC for further proceedings.

In September 2022, and in response to the Virginia Supreme Court opinion and subsequent Virginia SCC order initiating a remand proceeding, APCo submitted with the Virginia SCC: (a) an updated 2017-2019 Virginia earnings calculation resulting in a proposed $37 million regulatory asset related to previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band, (b) an updated requested annual base rate increase of $41 million effective October 2022 and (c) a requested rider to recover, over the period October 2022 through January 2024, approximately $72 million related to an APCo Virginia base rate increase for the period January 2021 through September 2022. APCo’s requested $41 million annual base rate increase includes

approximately $12 million related to the recovery of APCo’s regulatory asset for previously incurred costs as a result of earning below its 2017-2019 authorized ROE band. APCo implemented interim base rate and rider rate increases effective October 2022, both of which are subject to refund and review by the Virginia SCC. An order from the Virginia SCC in the remand proceeding is expected in the fourth quarter of 2022.

In September 2022, APCo expensed the remaining $25 million closed coal plant regulatory asset that was previously ordered by the Virginia SCC and recorded a $37 million regulatory asset for previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band. APCo’s October 2022 through January 2024 net income, cash flows and financial condition is expected to be positively impacted pending the Virginia SCC’s order on APCo’s requested base rate and rider rate increases.

In March 2023, APCo will submit its required Virginia earnings test calculation for the 2020-2022 Triennial Review 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 major storms, the early retirement of fossil fuel generating assets and certain projects necessary to comply with state and federal environmental legislation. As of September 2022, APCo has deferred approximately $25 million related to previously incurred costs as a result of the current estimate that APCo will earn below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period. If it is determined that APCo has earned above the bottom of its authorized ROE band for the 2020-2022 Triennial Review period it could reduce future net income and cash flows and impact financial conditions.

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. In August 2021, the Virginia SCC issued an order approving recovery of CCR-related operation and maintenance expenses and investments at the Amos and Mountaineer Plants through an active rider. The order also denied APCo’s request to recover the cost of ELG investments and denied recovery of previously incurred ELG costs, but did not preclude APCo from refiling for approval. In March 2022, APCo refiled for approval to recover the cost of the ELG investments and previously incurred ELG costs. Intervenor testimony was submitted in August 2022 recommending the denial of ELG cost recovery. In October 2022, a Virginia Hearing Examiner recommended that the Virginia SCC approve recovery of APCo’s requested ELG investment costs at Amos and Mountaineer Plants. Management expects to receive an order from the Virginia SCC 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 those 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 WVPSC also ordered that APCo will be given the opportunity to recover, from West Virginia customers, the ELG and 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. The October 2021 order further states that unless the Virginia jurisdictional customers of APCo pay for their share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the benefit of the capacity and energy made possible by those improvements and operating the Amos and Mountaineer Plants beyond 2028 should benefit only West Virginia and FERC jurisdictional customers who have shared in paying for those costs.

APCo expects the total Amos and Mountaineer Plant ELG investment, excluding AFUDC, to be approximately $162 million. As of September 30, 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 $62 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 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. Management expects to receive a WVPSC order on the Companies’ 2022 ENEC filing in the fourth quarter of 2022 and a separate WVPSC order on the prudency review of the Companies’ ENEC costs in the first quarter of 2023. As of September 30, 2022, the Companies’ cumulative ENEC under-recovery was $430 million. If any deferred ENEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In June 2022, the West Virginia service territories of APCo and WPCo (the Companies) were impacted by strong winds from multiple storms resulting in system damages and power outages. As of September 30, 2022, the Companies incurred and deferred an estimated $15 million in incremental distribution operation and maintenance expenses related to service restoration efforts. The Companies will seek recovery of these deferrals in future filings. If any of the storm restoration 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 September 30, 2022, AEP’s share of ETT’s cumulative revenues that are subject to review is approximately $1.5 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 $1.5 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. In May 2022, I&M submitted exceptions to the ALJ’s PFD related to the recommended disallowance of purchased power costs described above. I&M anticipates that the MPSC will issue a final decision in the fourth quarter 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.

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 August 2022, I&M submitted its FAC filing and earnings test evaluation for the period ended May 2022, which calculated a credit due to customers of $14 million. In October 2022, the IURC approved the FAC filing and earnings test evaluation, with the credit to customers starting in November 2022 through the FAC.

In February 2022, I&M filed a request with the MPSC for approval of its 2022 IRP. Included in that filing were requests for approval and deferral of costs associated with resources commencing construction within three years of the Commission’s order in the filing. These resources include the new generation resources expected to be in-service by 2028, and demand-side resources, including load management programs and conservation voltage reduction investments. I&M is also requesting MPSC approval of I&M’s Rockport Unit 2 transition plan consistent with that approved by the IURC, including certain cost recovery related to remaining net book value of leasehold improvements made during the term of the Rockport Unit 2 lease and future use of Rockport Unit 2 as a capacity resource. In addition, I&M has made requests for approval of a financial incentive on certain power purchase agreements and load management programs. As of September 30, 2022, I&M’s total net book value for these Rockport Unit 2 leasehold improvements was $102 million.

In June 2022, intervening parties recommended various adjustments to I&M’s proposals, including the process I&M would use to receive approval of new generation resources, changes to or denial of requested financial incentives and requests for deferral and pre-approval of costs. Specific to I&M’s Rockport Unit 2 transition plan, certain

intervening parties recommended that the MPSC order I&M to credit back to Michigan ratepayers the jurisdictional share of post-lease revenues in excess of costs from Rockport Unit 2’s operations as a merchant facility and that I&M only receive a post-lease debt return on remaining net book value of Rockport Unit 2 leasehold improvements. A hearing with the MPSC was held in August 2022.

Management currently anticipates that the MPSC will issue an order on I&M’s 2022 Michigan IRP filing in the first quarter of 2023. Any disallowance or reduction in the recovery of the I&M Michigan jurisdictional share of the Rockport Unit 2 leasehold improvements could reduce future net income and cash flows and impact financial condition.

KPCo and WPCo each own a 50% interest in the Mitchell Plant. As of September 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $576 million. 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 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 also ordered that WPCo will be given the opportunity to recover, from its customers, the ELG and 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. The WVPSC’s order further states that unless KPCo pays for its share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the benefit of the capacity and energy made possible by those improvements and operating Mitchell Plant beyond 2028 should benefit only West Virginia jurisdictional customers who have shared in paying for those costs.

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, if any, these disputes may have on future results of operations,

In June 2022, the service territory of OPCo was impacted by strong winds from multiple storms resulting in power outages and damage to the transmission and distribution infrastructures. As of September 30, 2022, OPCo had incurred approximately $19 million in incremental operation and maintenance costs related to service restoration efforts. The incremental storm restoration costs have been deferred as regulatory assets and OPCo is expected to seek recovery in a future filing. In July 2022, intervenors filed a motion requesting the PUCO open a formal investigation into the power outages that occurred as a result of the June storms and determine if OPCo was negligent and liable to consumers for damages incurred as a result of the power outages. If any of the storm restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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.

In April 2021, the OCC approved a waiver allowing the deferral of PSO’s extraordinary fuel costs and purchases of electricity as regulatory assets, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. Also in April 2021, legislation was enacted in Oklahoma permitting securitized financing of qualified costs from extreme weather events. This legislation provides certain authority to the OCC to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds issued by the ODFA, an Oklahoma governmental agency. In January 2022, PSO, OCC staff and certain intervenors filed a joint stipulation and settlement agreement with the OCC to approve the securitization of PSO’s extraordinary fuel costs and purchases of electricity. In February 2022, the OCC approved the joint stipulation and settlement agreement which included a determination that all of PSO’s extraordinary fuel costs and purchases of electricity were prudent and reasonable and also provided a 0.75% carrying charge related to those costs, subject to true-up based on actual financing costs.

In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. The securitization bonds are the obligation of the ODFA and there is no recourse against PSO in the event of a bond default, and therefore are not recorded as Long-term Debt on PSO’s balance sheet. PSO will serve as the servicing agent of the bonds and is responsible for the routine billing and collection of the securitization charges and remitting those collections back to the ODFA. The securitization charges billed to and collected from customers are not included as revenue on PSO’s statement of income. The collections from customers will occur over 20 years.

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. 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. SWEPCo plans to file a request for rehearing. If SWEPCo’s request for rehearing is denied, the case will be 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 September 30, 2022. 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 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 September 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. 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 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 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 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 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 August 2022, in a separate proceeding, the LPSC staff recommended recovery of, but no return on, the Dolet Hills Power Station based on a five-year recovery period if the remaining net book value is not recovered utilizing securitization. Additionally, the LPSC staff recommended that the remaining net book value be reduced for depreciation expenses, and operation and maintenance costs in rates since the plant was retired in December 2021.

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

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. In January 2022, SWEPCo filed testimony revising the requested annual increase in Arkansas base rates to $81 million. SWEPCo requested that rates become effective in June 2022.

In May 2022, the APSC issued a final order approving an annual revenue increase of $49 million based upon a 9.5% ROE. The order also includes: (a) a capital structure of 55% debt and 45% common equity, (b) approval to recover the Dolet Hills Power Station as a regulatory asset over five years without a return on this investment resulting in an immaterial disallowance in the second quarter of 2022, (c) the denial of accelerated depreciation for the Pirkey Plant and Welsh Plant, Units 1 and 3 and (d) approval of a rider to recover SPP costs and revenues. The final order also denied the inclusion of the stand-alone NOLC in SWEPCo’s deferred tax assets, but included approval of the deferral of the forgone revenue requirement associated with the NOLC and excess NOLC, with recovery of the deferral contingent upon receipt of a supportive private letter ruling from the IRS. Rates were implemented with the first billing cycle of July 2022.

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. In May 2022, LPSC staff testimony was submitted to the LPSC. In July 2022, SWEPCo filed rebuttal testimony which agreed to make a request for securitization as the LPSC staff had recommended in their testimony. 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 $349 million as of September 30, 2022, of which $85 million, $126 million and $138 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. In April 2021, SWEPCo filed testimony supporting a

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 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 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 September 30, 2022, AEP’s share of IEC capital expenditures was approximately $83 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 Consumers’ Counsel 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 Consumers’ Counsel’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. 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.