As discussed in the 2019 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2019 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 2020 and updates the 2019 Annual Report.



Plant	Gross Investment		Accumulated Depreciation		Net Investment		Accelerated Depreciation Regulatory Asset			Materials and Supplies		Cost of Removal Regulatory Liability		Expected Retirement Date	Remaining Recovery Period
	(dollars in millions)
Oklaunion Power Station	$	106.8	$	92.6	$	14.2	$	33.0	(a)	$	3.3	$	5.2	2020	27 years
Dolet Hills Power Station	341.4		205.0		136.4		9.1		(b)	5.8		23.7		2021	27 years

During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In January 2020, in accordance with the terms of SWEPCo’s settlement of its base rate review filed with the APSC, management announced that SWEPCo will seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. DHLC provides 100% of the fuel supply to Dolet Hills Power Station. In March 2020, it was determined that DHLC would not proceed developing additional mining areas for future lignite extraction and management notified a substantial portion of its workforce that employment will permanently end in June 2020. Based on these actions, management has revised the estimated useful life of many of DHLC’s assets to June 2020 to coincide with the date at which extraction is expected to be discontinued. Management also revised the useful life of the Dolet Hills Power Station to September 2021 based on the remaining estimated fuel supply available for continued seasonal operation. In March 2020, primarily due to the revision in the useful life of DHLC, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the pending cessation of lignite mining in June 2020.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the Lignite Mining Agreement, DHLC bills SWEPCo its proportionate share of incurred lignite extraction and associated mining-related costs as fuel is delivered. As of March 31, 2020, DHLC has unbilled lignite inventory and fixed costs of $124 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. In 2009, SWEPCo acquired interests in the Oxbow Lignite Company (Oxbow), which owns mineral rights and leases land. Under a Joint Operating Agreement pertaining to the Oxbow mineral rights and land leases, Oxbow bills SWEPCo its proportionate share of incurred costs. As of March 31, 2020, Oxbow has unbilled fixed costs of $26 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. Additional operational and land-related costs are expected to be incurred by DHLC and Oxbow and billed to SWEPCo prior to the closure of the Dolet Hills Power Station and recovered through fuel clauses.



	AEP
	March 31,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Plant Retirement Costs – Unrecovered Plant	$	35.2	$	35.2
Oklaunion Power Station Accelerated Depreciation	33.0		27.4
Kentucky Deferred Purchase Power Expenses	32.9		30.2
Dolet Hills Power Station Accelerated Depreciation	9.1		—
Other Regulatory Assets Pending Final Regulatory Approval	2.1		0.7
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		30.1
Asset Retirement Obligation	7.7		7.2
Storm-Related Costs	7.3		7.2
Vegetation Management Program (a)	3.8		29.4
Cook Plant Study Costs (b)	—		7.6
Other Regulatory Assets Pending Final Regulatory Approval	5.0		6.7
Total Regulatory Assets Pending Final Regulatory Approval (c)	$	162.0	$	181.7



	APCo
	March 31,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Plant Retirement Costs – Materials and Supplies	$	—	$	0.5
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		30.1
Total Regulatory Assets Pending Final Regulatory Approval (a)	$	25.9	$	30.6



	PSO
	March 31,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Oklaunion Power Station Accelerated Depreciation	$	33.0	$	27.4
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	7.3		7.2
Total Regulatory Assets Pending Final Regulatory Approval	$	40.3	$	34.6



	SWEPCo
	March 31,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Plant Retirement Costs – Unrecovered Plant, Louisiana	$	35.2	$	35.2
Dolet Hills Power Station Accelerated Depreciation	9.1		—
Other Regulatory Assets Pending Final Regulatory Approval	2.2		0.2
Regulatory Assets Currently Not Earning a Return
Asset Retirement Obligation - Louisiana	7.7		7.2
Other Regulatory Assets Pending Final Regulatory Approval	1.9		3.7
Total Regulatory Assets Pending Final Regulatory Approval	$	56.1	$	46.3

AEP’s electric utility operating companies have informed retail customers and state regulators that disconnections for non-payment have been temporarily suspended. These uncertain economic conditions may result in the inability of customers to pay for electric service, which could affect the collectability of the Registrants revenues and adversely affect financial results. The Registrants are currently evaluating and working with regulatory commissions on potential rate recovery for increased costs as a result of the impacts of COVID-19. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition. The table below describes the key elements of orders received, by jurisdiction, in response to COVID-19:



Company	Jurisdiction		Order
AEP Texas, ETT, SWEPCo	Texas	•	Established a COVID-19 Electricity Relief Program to be funded through a rider for eligible residential customers in the areas of the state open to customer choice (AEP Texas only).
		•	Granted permission for utilities to record a regulatory asset for expenses including, but not limited to, non-payment of qualified customer bills who have been affected by the COVID-19 pandemic.
APCo	Virginia	•	Granted permission for utilities to defer expenses related to the COVID-19 pandemic. Deferral will be subject to APCo’s Virginia earnings test during the 2020-2022 Triennial period.
I&M	Michigan	•	Granted permission for utilities to defer certain expenses related to the COVID-19 pandemic.
SWEPCo	Arkansas	•	Granted permission for utilities to establish a regulatory asset to record costs resulting from the suspension of disconnections offset by any cost savings directly attributable to the suspension of disconnections or other activities during the COVID-19 pandemic.
SWEPCo	Louisiana	•	Granted permission for utilities to record a regulatory asset for expenses resulting from the suspension of disconnections and collection of late fees related to the COVID-19 pandemic.

In May 2019, AEP Texas filed a request with the PUCT for a $56 million annual increase in rates based upon a proposed 10.5% return on common equity. The filing included a proposed Income Tax Refund Rider that will refund $21 million annually of Excess ADIT that is primarily not subject to normalization requirements. The rate case also sought a prudence determination on all transmission and distribution capital additions through 2018 included in interim rates from 2008 to December 2019.

In April 2020, the PUCT issued an order approving a stipulation and settlement agreement. The order includes an annual base rate reduction of $40 million based upon a 9.4% return on common equity with a capital structure of 57.5% debt and 42.5% common equity effective with the first billing cycle in June 2020. The order provides recovery of $26 million in capitalized vegetation management expenses that were incurred through 2018. The order includes disallowances of $23 million related to capital investments recorded through 2018 and $4 million related to rate case expenses. In addition, AEP Texas will refund: (a) $77 million of Excess ADIT and excess federal income taxes collected as a result of Tax Reform to distribution customers over a one year period, (b) $31 million of Excess ADIT and excess federal income taxes collected as a result of Tax Reform to transmission customers as a one-time credit and (c) $30 million of previously collected rates that were subject to reconciliation in this proceeding over a one year period with no carrying costs. The order requires AEP Texas to file its next base rate case within four years of the date of that the final order was issued. The order also states future financially based capital incentives will not be included in interim transmission and distribution rates and contains various ring-fencing provisions. As a result of the final order, AEP Texas will refund $275 million of Excess ADIT associated with certain depreciable property using ARAM to transmission customers. AEP Texas will determine how to refund the remaining Excess ADIT that is not subject to normalization requirements in future proceedings.

In December 2019, as a result of the initial stipulation and settlement agreement, AEP Texas (a) recorded an impairment of $33 million related to capital investments, which included $10 million of 2019 investments, in Asset Impairments and Other Related Charges on the statements of income, (b) recorded a $30 million provision for refund on the statements of income for revenues previously collected through rates and (c) wrote-off $4 million of rate case expenses to Other Operation on the statements of income.

Amendments to Virginia law impacting investor-owned utilities were enacted, effective July 1, 2018, that required APCo to file a generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 earnings test years (triennial review). Triennial reviews are subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. In November 2018, the Virginia SCC authorized a ROE of 9.42% applicable to APCo base rate earnings for the 2017-2019 triennial period.

Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. In 2015, APCo retired the Sporn Plant, the Kanawha River Plant, the Glen Lyn Plant, Clinch River Unit 3 and the coal portions of Clinch River Units 1 and 2 (collectively, the retired coal-fired generation assets). The net book value of these plants at the retirement date was $93 million before cost of removal, including materials and supplies inventory and ARO balances. Based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million related to its previously retired coal-fired generation assets in December 2019. As a result, management deems these costs to be substantially recovered by APCo during the triennial review period.

In March 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $65 million annual increase based upon a proposed 9.9% return on common equity. The requested annual increase includes $19 million related to depreciation for updated test year end depreciable balances and a proposed increase in APCo’s Virginia depreciation rates and $8 million related to APCo’s calculated shortfall in 2017-2019 APCo’s Virginia earnings. Inclusive of the $93 million expense associated with APCo’s Virginia jurisdictional retired coal-fired plants, APCo calculated its 2017-2019 Virginia earnings for the triennial period to be below the authorized ROE range.

APCo is currently in the process of retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of March 31, 2020 and December 31, 2019, APCo has approximately $52 million and $51 million of Virginia jurisdictional AMR meters recorded in Total Property, Plant and Equipment - Net on its balance sheets. APCo is pursuing full recovery of these assets through its Virginia depreciation rates as discussed above.

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, 2020, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $1.1 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.

In May 2019, I&M filed a request with the IURC for a $172 million annual increase. The requested increase in Indiana rates would be phased in through January 2021 and was based upon a proposed 10.5% return on common equity. The proposed annual increase included $78 million related to a proposed annual increase in depreciation expense. The requested annual increase in depreciation expense included $52 million related to proposed investments and $26 million related to increased depreciation rates. The request included the continuation of all existing riders and a new AMI rider for proposed meter projects.

In March 2020, the IURC issued an order authorizing a $77 million annual base rate increase based upon a return on common equity of 9.7% effective March 2020. This increase will be phased in through January 2021 with an approximate $44 million annual increase in base rates effective March 2020 and the full $77 million annual increase effective January 2021. The order approved the majority of I&M’s proposed changes in depreciation. The order also approved the test year level of AMI deployment but did not approve a cost recovery rider for AMI investments made in subsequent years. The order rejected I&M’s proposed re-allocation of capacity costs related to the loss of a significant FERC wholesale contract, which will negatively impact I&M’s annual pretax earnings by approximately $20 million starting June 2020. In March 2020, I&M filed for rehearing as a result of the IURC’s ruling to reject I&M’s proposed re-allocation of capacity costs. Intervenors subsequently filed objections to I&M's appeal. In April 2020, I&M filed a reply to these objections on rehearing and appealed the IURC’s order.

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. The resulting annual base rate increase was approximately $52 million. 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 the fourth quarter of 2019 and first quarter of 2020, SWEPCo and various intervenors filed briefs with the Texas Supreme Court.

As of March 31, 2020, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately fully recover its approximate 33% Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.

In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a return on common equity 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. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition.

In April 2018, SWEPCo filed its formula rate plan for test year 2017 with the LPSC. The filing included a net $28 million annual increase, which was effective August 2018 and included SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls. The filing also included a reduction in the federal income tax rate due to Tax Reform but did not address the return of Excess ADIT benefits to customers.

In July 2018, SWEPCo made a supplemental filing to its formula rate plan with the LPSC to reduce the requested annual increase to $18 million. The difference between SWEPCo’s requested $28 million annual increase and the $18 million annual increase in the supplemental filing is primarily the result of the return of Excess ADIT benefits to customers.

In October 2018, the LPSC staff issued a recommendation that SWEPCo refund $11 million of excess federal income taxes collected, as a result of Tax Reform, from January 1, 2018 through July 31, 2018. In June 2019, the LPSC staff issued its report which reaffirmed its $11 million refund recommendation. The report also contends that SWEPCo’s requested annual rate increase of $18 million, which was implemented in August 2018, is overstated by $4 million and proposes an annual rate increase of $14 million. Additionally, the report recommends SWEPCo refund the excess over-collections associated with the $4 million difference for the period of August 2018 through the implementation of new rates. In July 2019, the LPSC approved the $11 million refund. A decision by the LPSC on the remaining formula rate plan issues is expected in the second quarter of 2020. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.