~~0000004904 aep:AEPTransmissionCoMember aep:AEPTCoParentMember 2020-01-01 2020-03-31~~

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

~~10-Q~~

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended March 31, ~~2020~~2021

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For The Transition Period from ____ to ____



Commission	Registrants;						I.R.S. Employer
File Number	Address and Telephone Number					States of Incorporation	Identification Nos.

1-3525	AMERICAN ELECTRIC POWER CO INC.					New York	13-4922640
333-221643	AEP TEXAS INC.					Delaware	51-0007707
333-217143	AEP TRANSMISSION COMPANY, LLC					Delaware	46-1125168
1-3457	APPALACHIAN POWER COMPANY					Virginia	54-0124790
1-3570	INDIANA MICHIGAN POWER COMPANY					Indiana	35-0410455
1-6543	OHIO POWER COMPANY					Ohio	31-4271000
0-343	PUBLIC SERVICE COMPANY OF OKLAHOMA					Oklahoma	73-0410895
1-3146	SOUTHWESTERN ELECTRIC POWER COMPANY					Delaware	72-0323455
	1 Riverside Plaza,		Columbus,	Ohio	43215-2373
	Telephone	(614)	716-1000

Securities registered pursuant to Section 12(b) of the Act:

Registrant

Title of each class

Trading Symbol

Name of Each Exchange on Which Registered

American Electric Power Company Inc.

Common Stock, $6.50 par value

AEP

~~New York~~The NASDAQ Stock ~~Exchange~~Market LLC

American Electric Power Company Inc.

6.125% Corporate Units

~~AEP PR B~~AEPPL

~~New York~~The NASDAQ Stock ~~Exchange~~Market LLC

American Electric Power Company Inc.

6.125% Corporate Units

AEPPZ

The NASDAQ Stock Market LLC

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Yes

☐

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).

Yes

☐

Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated filer

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

Indicate by check mark whether AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated filer

☐

Accelerated filer

☐

Non-accelerated filer

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

☐

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).

Yes

☐

AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.



	~~Number of shares~~ ~~of common stock~~ ~~outstanding of the~~ ~~Registrants as of~~
	~~May 6, 2020~~

~~American Electric Power Company, Inc.~~	~~495,583,133~~
	~~($6.50 par value)~~
~~AEP Texas Inc.~~	~~100~~
	~~($0.01 par value)~~
~~AEP Transmission Company, LLC (a)~~	NA

~~Appalachian Power Company~~	~~13,499,500~~
	~~(no par value)~~
~~Indiana Michigan Power Company~~	~~1,400,000~~
	~~(no par value)~~
~~Ohio Power Company~~	~~27,952,473~~
	~~(no par value)~~
~~Public Service Company of Oklahoma~~	~~9,013,000~~
	~~($15 par value)~~
~~Southwestern Electric Power Company~~	~~7,536,640~~
	~~($18 par value)~~


~~(a)~~	~~100% interest is held by AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of American Electric Power Company, Inc.~~


NA	~~Not applicable.~~



			Number of shares of common stock outstanding of the Registrants as of
			April 22, 2021

American Electric Power Company, Inc.			499,750,400
			($6.50 par value)
AEP Texas Inc.			100
			($0.01 par value)
AEP Transmission Company, LLC (a)			NA

Appalachian Power Company			13,499,500
			(no par value)
Indiana Michigan Power Company			1,400,000
			(no par value)
Ohio Power Company			27,952,473
			(no par value)
Public Service Company of Oklahoma			9,013,000
			($15 par value)
Southwestern Electric Power Company			3,680
			($18 par value)

(a)100% interest is held by AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of American Electric Power Company, Inc.

NA Not applicable.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF QUARTERLY REPORTS ON FORM 10-Q

March 31, ~~2020~~2021

Page

Number

Glossary of Terms

Forward-Looking Information

Part I. FINANCIAL INFORMATION

Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Controls and Procedures:

American Electric Power Company, Inc. and Subsidiary Companies:

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Condensed Consolidated Financial Statements

3945

AEP Texas Inc. and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

4652

Condensed Consolidated Financial Statements

4855

AEP Transmission Company, LLC and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

5562

Condensed Consolidated Financial Statements

5763

Appalachian Power Company and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

6369

Condensed Consolidated Financial Statements

6671

Indiana Michigan Power Company and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

7378

Condensed Consolidated Financial Statements

7680

Ohio Power Company and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

8387

Condensed Consolidated Financial Statements

8690

Public Service Company of Oklahoma:

Management’s Narrative Discussion and Analysis of Results of Operations

9397

Condensed Financial Statements

9599

Southwestern Electric Power Company Consolidated:

Management’s Narrative Discussion and Analysis of Results of Operations

~~102~~106

Condensed Consolidated Financial Statements

~~104~~108

Index of Condensed Notes to Condensed Financial Statements of Registrants

~~110~~114

Controls and Procedures

~~179~~193

Part II. OTHER INFORMATION

Item 1.

Legal Proceedings

~~180~~194

Item 1A.

Risk Factors

~~180~~194

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

~~180~~194

Item 3.

Defaults Upon Senior Securities

~~180~~194

Item 4.

Mine Safety Disclosures

~~180~~194

Item 5.

Other Information

~~181~~194

Item 6.

Exhibits

~~181~~195

SIGNATURE

~~182~~197

This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.


Term						Meaning

DHLC						Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.


Term		Meaning

OPEB		Other Postretirement Benefits.
~~OSS~~		~~Off-system Sales.~~
OTC		Over-the-counter.
OVEC		Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent		American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PATH-WV		PATH West Virginia Transmission Company, LLC, a joint venture owned 50% by FirstEnergy and 50% by AEP.
PJM		Pennsylvania – New Jersey – Maryland regional transmission organization.
PM		Particulate Matter.
PPA		Purchase Power and Sale Agreement.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTC		Production Tax Credits.
PUCO		Public Utilities Commission of Ohio.
PUCT		Public Utility Commission of Texas.
Racine		A generation plant consisting of two hydroelectric generating units totaling 48 MWs located in Racine, Ohio and owned by AGR.
~~Reference Rate Reform~~		~~The global transition away from referencing the London Interbank Offered Rate and other interbank offered rates, and toward new reference rates that are more reliable and robust.~~
Registrant Subsidiaries		AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants		SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Restoration Funding		AEP Texas Restoration Funding LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey.
Risk Management Contracts		Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant		A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
ROE		Return on Equity.
RPM		Reliability Pricing Model.
RTO		Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine		Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo.
~~Santa Rita East~~		~~Santa Rita East Wind Holdings, LLC, a consolidated VIE whose sole purpose is to own~~
SEC		U.S. Securities and ~~operate a 302.4 MW wind generation facility in west Texas in which AEP owns a 75% interest.~~Exchange Commission.
Sempra Renewables LLC		Sempra Renewables LLC, acquired in April 2019, consists of 724 MWs of wind generation and battery assets in the United States.
SIP		State Implementation Plan.
SNF		Spent Nuclear Fuel.
SO₂		Sulfur dioxide.
SPP		Southwest Power Pool regional transmission organization.
~~SSO~~	~~Standard service offer.~~


Term		Meaning
		~~Formerly AEP Texas Central Company, now a division of AEP Texas.~~
~~Texas Restructuring Legislation~~	~~Legislation enacted in 1999 to restructure the electric utility industry in Texas.~~
Transition Funding		AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated ~~VIEs~~VIE formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. In July 2020, the final AEP Texas Central Transition Funding II securitization bond matured.
Transource Energy		Transource Energy, LLC, a consolidated VIE formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.

Turk Plant		John W. Turk, Jr. Plant, a ~~600~~650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
~~UPA~~	~~Unit Power Agreement.~~
Utility Money Pool		Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE		Variable Interest Entity.
Virginia SCC		Virginia State Corporation Commission.
~~Wind Catcher Project~~	Wind Catcher Energy Connection Project, a joint PSO and SWEPCo project that was cancelled in July 2018. The project included the acquisition of a wind generation facility, totaling approximately 2,000 MW of wind generation, and the construction of a generation interconnection tie-line totaling approximately 350 miles.
WPCo		Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC		Public Service Commission of West Virginia.

FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Many forward-looking statements appear in ~~“Item 7~~“Part 1 – Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations” of ~~the 2019 Annual Report,~~this quarterly report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook. These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected. Forward-looking statements in this document are presented as of the date of this document. Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:



•			Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.
•			The impact of pandemics, including COVID-19, and any associated disruption of AEP’s business operations due to impacts on economic or market conditions, electricity usage, employees, customers, service providers, vendors and suppliers.
•			Inflationary or deflationary interest rate trends.
•			Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
•			The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
•			Decreased demand for electricity.
•			Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
•			The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and SNF.
•			The availability of fuel and necessary generation capacity and the performance of generation plants.
•			The ability to recover fuel and other energy costs through regulated or competitive electric rates.
•			The ability to build or acquire renewable generation, transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms, including favorable tax treatment, and to recover those costs.
•			New legislation, litigation and government regulation, including changes to tax laws and regulations, oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or PM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.
•			Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including coal ash and nuclear fuel.
•			Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
•			Resolution of litigation.
•			The ability to constrain operation and maintenance costs.
•			Prices and demand for power generated and sold at wholesale.
•			Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
•			The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
•			Volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas.
•			Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP.
•			Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
•			Actions of rating agencies, including changes in the ratings of debt.


•
•	The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.


•			Accounting standards periodically issued by accounting standard-setting bodies.
•			Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires, ~~cyber~~cyber- security threats and other catastrophic events.
•			The ability to attract and retain the requisite work force and key personnel.

The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made. The Registrants expressly disclaim any obligation to update any forward-looking ~~information.~~information, except as required by law. For a more detailed discussion of these factors, see “Risk Factors” in Part I of the ~~2019~~2020 Annual Report and in Part II of this report.

Investors should note that the Registrants announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, the Registrants may use the Investors section of AEP’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financial and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

Impacts of Severe Winter Weather

In February 2021, severe winter weather impacted the service territories of APCo, KPCo, PSO and SWEPCo resulting in power outages, extensive damage to infrastructure and disruptions to SPP market conditions. Impacts of the severe winter weather are included below. See Note 4 - Rate Matters for additional information.

Storm Restoration Costs

The impact of the severe winter weather resulted in power outages and extensive damage to transmission and distribution infrastructures across the service territories of APCo, KPCo and SWEPCo. As of March 31, 2021, an estimated $57 million of capital expenditures and $137 million of restoration expenses have been incurred related to the severe winter weather. Approximately $131 million of the expenses represent incremental restoration expenses and have been deferred as regulatory assets. The KPSC and LPSC issued orders authorizing the deferral of incremental restoration expenses as regulatory assets. APCo and KPCo intend to seek recovery of these restoration costs in their next respective base rate cases while SWEPCo is expected to seek recovery in a separate filing. If any of the restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

The severe winter weather also 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.

As of March 31, 2021, PSO and SWEPCo have deferred regulatory assets of $689 million and $496 million, respectively, relating to estimated natural gas expenses and purchases of electricity incurred from February 9, 2021, to February 20, 2021, as a result of severe winter weather. These amounts represent estimates as of March 31, 2021, and are subject to final settlement as additional information becomes available. PSO and SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. Given the significance of these costs, PSO and SWEPCo expect the costs to be subject to prudency reviews. Management believes these costs are probable of future recovery, but expects the recovery period to be extended to mitigate the impact on customer bills.

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. Accordingly, in April 2021, SWEPCo began recovery of its Arkansas jurisdictional share of these fuel costs, which are subject to true-up by the APSC. Also in April 2021, SWEPCo filed testimony supporting a five-year recovery with a pretax rate of return of 6.05%. A hearing is expected in the third quarter of 2021. A separate proceeding will address the prudency of the fuel costs.

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

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchase of electricity costs, including carrying costs, over a longer time period than what the FAC traditionally allows. A time frame for recovery and the appropriate carrying charge will be decided at a later date. Also in April 2021, legislation was introduced in Oklahoma proposing to securitize the extraordinary fuel and purchase of electricity costs impacting the utilities within the state. Under the proposal, the State of Oklahoma would issue securitization bonds and provide the proceeds to utilities to recover their share of the costs. PSO will continue to evaluate and monitor the advancement of the proposed legislation.

SWEPCo expects to make a filing with the PUCT in the second quarter of 2021 to seek a recovery mechanism and an appropriate carrying charge for the Texas jurisdictional share of the retail fuel costs.

SWEPCo is also working with certain wholesale customers to establish payment terms for $88 million of accounts receivable resulting from the severe winter weather events. Management believes these receivables are probable of future collection.

PSO and SWEPCo Cash Flow Implications

PSO and SWEPCo evaluated financing alternatives to address the timing difference between the payment of the estimated natural gas expenses and purchases of electricity to suppliers and subsequent recovery from customers. In March 2021, PSO drew $100 million on its revolving credit facility and SWEPCo issued $500 million of Senior Unsecured Notes. In March 2021, Parent entered into a $500 million 364-day Term Loan and borrowed the full amount. The proceeds from this loan were used to help fund capital contributions to PSO and SWEPCo totaling $425 million and $100 million, respectively. In April 2021, PSO received an additional capital contribution from Parent of $125 million to further address these costs.

Although the February 2021 severe winter weather did not materially impact AEP’s results of operations for the three months ended March 31, 2021, if either PSO or SWEPCo is unable to recover these fuel and purchased power costs, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

In response to the extreme winter weather event, the Governor of Texas issued a Declaration of a State of Disaster for all counties in Texas. To assist with a return to normalcy, the PUCT issued an order that placed a temporary moratorium on customer disconnections due to non-payment for transmission and distribution utilities. This moratorium will be in effect until otherwise ordered by the PUCT. If related costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In ~~March~~ 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention. Its rapid spread around the world and throughout the United States prompted many countries, including the United States, to institute restrictions on travel, public gatherings and certain business operations. These restrictions significantly disrupted economic activity in AEP’s service territory and ~~could reduce future~~resulted in reduced demand for energy, particularly from commercial and industrial customers. ~~As of March 31, 2020, the reduction in the~~Management expects weather-normalized customer demand ~~for energy did not materially impact the Registrants’ financial statements.~~to continue to improve during 2021 as additional vaccinations occur and economic activity improves. However, if the severity of the economic ~~disruptions increase as the duration~~disruption increases, AEP’s future results of ~~the COVID-19 pandemic continues, the negative~~operations, financial ~~impact due to reduced demand~~condition, and cash flows could be ~~significantly greater in future periods than in the first quarter.~~further adversely impacted.

During 2020, AEP’s electric ~~utility~~ operating companies informed both retail customers and state regulators that disconnections for non-payment ~~have been~~were temporarily suspended. ~~These uncertain~~Shortly thereafter, AEP’s state regulators also imposed temporary moratoria on customary disconnection practices. As of March 31, 2021, AEP’s electric operating companies have resumed customary disconnection practices in all regulated jurisdictions with the exception of Arkansas and Virginia. In March 2021, the APSC issued an order allowing electric utilities in Arkansas to begin disconnections for non-payment beginning on May 3, 2021. AEP continues to work with regulators and stakeholders in Virginia and management currently anticipates resuming customary disconnection practices in the third quarter of 2021. Continuing adverse economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and the collectability of ~~the Registrants’ revenues and adversely affect financial results.~~ accounts receivable.

The Registrants ~~are evaluating~~continue to review current accounts receivable collection experience with historical trends, specifically reviewing metrics such as cash collections, days sales outstanding, daily customer deposits, and ~~working~~aging summaries. In addition, the Registrants reviewed historical loss information generally comprised of a rolling 12-month average, in conjunction with ~~their state regulatory commissions on potential rate recovery mechanisms for increased costs incurred due to COVID-19. Certain Registrants received orders approving~~a qualitative assessment of elements that impact the ~~deferral~~collectability of certain incremental expenses associated with COVID-19. See Note 4 - Rate Matters for additional information. The Registrants have not observed a material change in their typical collections experience and thus did not materially adjust their allowances for uncollectible accountsreceivables, such as ~~of March 31, 2020.~~

The effects of the continued outbreak of COVID-19 and related government responses could also include extended disruptions to supply chains and capital markets, reduced labor availability and a prolonged reductionchanges in economic ~~activity. These effects could have a variety of adverse impacts~~factors, regulatory matters, industry trends, customer credit factors, payment plan options and other programs available to ~~the Registrants, including their ability~~customers. AEP has been and continues to ~~operate their facilities.~~be proactive in engaging with customers to collect payments or establish payment arrangements for outstanding balances. As of March 31, ~~2020, there were no~~2021, AEP currently does not expect accounts receivable aging to have a material adverse impact on the Registrants’ allowance for uncollectible accounts based on considerations of the COVID-19 impacts and past trends during times of economic instability. Management continues to monitor developments that could have an impact on customer collections.

Market volatility and delayed customer accounts receivable collections due to the ~~Registrants’~~expansion of customer payment arrangements could reduce cash from operations ~~due~~and cause an adverse impact to ~~COVID-19.~~

In addition, the economic disruptions caused by COVID-19 could also adversely impact the impairment risks for certain long-lived assets, equity method investments and goodwill. AEP evaluated these impairment considerations and determined that no such impairments occurred as of March 31, 2020.

During the first quarter of 2020, AEP increased its liquidity position to mitigate the risk of market volatility due to COVID-19. The Registrants’ access to funding was limited for a period of time during the first quarter and therefore AEP entered into a 364–day term loan to reduce reliance on commercial paper and help mitigate potential future liquidity risks. Specifically, for the first three months of 2020, AEP issued approximately $1.4 billion in long-term debt and $1.6 billion in short-term debt primarily via a 364-day term loan to enhance the Registrants’ available liquidity. As of March 31, ~~2020,~~2021, AEP’s available liquidity ~~is $2.8~~was $3.4 billion. Management believes the Registrants have adequate liquidity under existing credit facilities. To the extent that future access to the capital markets or the cost of funding is adversely affected by COVID-19, ~~the Registrants may need to consider alternative sources of funding for operations and working capital, which may adversely impact~~ future results of operations, financial condition, and cash ~~flows.~~flows may be adversely impacted.

The effects of an extended disruption to the supply chains could disrupt or delay construction, testing, supervisory and support activities at renewable generation facilities, in particular, the North Central Wind Energy Facilities and the AEP Generation & Marketing segment’s Flat Ridge 3 wind project. The in-service dates for the North Central Wind Energy Facilities are scheduled for end of year 2020 for one project, and end of year 2021 for the remaining two projects. Under the terms of the Purchase and Sales Agreement, PSO and SWEPCo do not have an obligation to acquire the North Central Wind Energy Facility projects if the projects are not completed by the required in-service dates. The in-service date for the Flat Ridge 3 wind project is scheduled for end of the year 2020. As of March 31, 2020, there has been no material adverse impacts to either the North Central Wind Energy Facility or the Flat Ridge 3 project. AEP currently expects the construction projects to be delivered on-time in accordance with the agreements with the developers. However, depending on the longevity and ultimate impact of COVID-19, future delays in the construction of AEP’s renewable assets could occur which could impact the current construction schedule, budget, and the qualification for federal PTC. AEP is working with industry groups on potential legislative and administrative relief for a PTC continuity safe harbor extension due to the ongoing impacts of COVID-19.

In March 2020, President Trump signed into law legislation referred to as the "Coronavirus Aid, Relief, and Economic Security Act" (the CARES Act). The CARES Act includes tax relief provisions such as: (a) an Alternative Minimum Tax (AMT) Credit Refund, (b) a 5-year net operating losses (NOL) carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. As of March 31, 2020, AEP has a $20 million AMT credit refund recognized in anticipation of a refund from the U.S. Treasury. Management is evaluating the ability to recover taxes paid in 2014 under the 5-year NOL carryback provision. The Registrants currently expect to defer payments of the employer share of payroll taxes for the period March 27, 2020 through December 31, 2020 and pay 50% of the obligation by December 31, 2021 and the remaining 50% by December 31, 2022.

The Registrants ~~are taking~~continue to take steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. The Registrants have updated and implemented a company-wide pandemic plan to address specific aspects of ~~the~~ COVID-19. This plan guides emergency response, business continuity, and the precautionary measures AEP is taking on behalf of its employees and the public. The Registrants ~~have taken~~continue to take extra precautions for employees who work in the field and for employees who work in their facilities, and have ~~implemented~~ work from home policies where appropriate. The Registrants will continue to monitor developments affecting both their workforce and customers, and will take additional precautions that management determines are necessary in order to mitigate the impacts. AEP continues to focus on providing safe, uninterrupted service to its customers, which includes the implementation of strong physical and cyber-security measures to ensure that its systems remain functional with a partially remote workforce. As of March 31, ~~2020,~~2021, there has been no material adverse impact to the Registrants’ business operations and customer service due to remote work. Management will continue to review and modify plans as conditions change. Despite efforts to manage these impacts to the Registrants, the ultimate impact of COVID-19 also depends on factors beyond management’s knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, management cannot estimate the potential future impact to financial position, results of operations and cash flows, but the impacts could be material.

AEP’s weather-normalized retail sales volumes for the first quarter of ~~2020~~2021 decreased by ~~0.7%~~1.9% from the first quarter of ~~2019.~~2020. Weather-normalized residential sales increased by 1.5% in the first quarter of 2021 from the first quarter of 2020. AEP’s first quarter ~~2020~~2021 industrial sales volumes decreased by ~~0.7%~~6.1% compared to the first quarter of ~~2019.~~2020. The decline in industrial sales was spread across many industries. Industrial sales were also negatively impacted by the severe winter event in AEP’s western operating territories in February 2021. Weather-normalized ~~residential~~commercial sales decreased ~~1.2% while weather-normalized commercial sales were flat~~1.6% in the first quarter of ~~2020,~~2021 from the first quarter of ~~2019.~~2020.

Many businesses were forced to limit or reduce their operations in response to the COVID-19 outbreak over the last two weeks of the first quarter of 2020. While there is uncertainty regarding the duration and total impact that COVID-19 will have on AEP’s retail sales in 2020, AEP expects COVID-19 to have a larger impact in the second quarter of 2020 than it had in the first quarter.

As a result of the impact of COVID-19, AEP revised its forecast for 2020 weather-normalized retail sales volumes from the forecast presented in the 2019 10-K. In 2020, AEP currently anticipates weather-normalized retail sales volumes will decrease by 3.4%. AEP expects industrial class sales volumes to decrease by 8% in 2020, while weather-normalized residential sales volumes are projected to increase by 3%. Finally, AEP currently projects weather-normalized commercial sales volumes to decrease by 5.6%.

AEP’s public utility subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Depending on the outcomes, these rate and regulatory proceedings can have a material impact on results of operations, cash flows and possibly financial condition. AEP is currently involved in the following key proceedings. See Note 4 - Rate Matters for additional information.

~~2019 Indiana Base Rate Case -~~ In May 2019, I&M filed a request with the IURC for a $172 million annual increase based upon a proposed 10.5% return on common equity. 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 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. The IURC also rejected I&M’s proposed AMI meter rider. 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.

•2017-2019 Virginia Triennial Review - 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).

~~2017-2019 Virginia Triennial Review~~ ~~- In March~~

In December 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. Triennial reviews are subject to 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 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. 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. Based on management’s interpretation of Virginia law and more certainty regarding~~approved regulatory asset for 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~~closed coal-fired generation assets, (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 and (c) the reasonableness and prudency of APCo’s investments in AMI meters.

In December ~~2019. As~~2020, APCo filed a ~~result, management deems these~~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 on APCo’s ability 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, the Virginia SCC issued an order confirming certain of its decisions from the November 2020 order and rejecting the various requests for reconsideration from APCo and an intervenor. In confirming its decision to reject an intervenor’s recommendation that APCo’s AMI costs ~~to be substantially recovered by APCo~~incurred during the triennial ~~review period. Inclusive~~period be disallowed, the Virginia SCC clarified that APCo established the need to replace its existing AMR meters, and that based on the uncertainty surrounding the continued manufacturing and support of AMR technology, APCo reasonably chose to replace them with AMI meters. In March 2021, APCo filed a notice of appeal of the ~~$93~~reconsideration order with the Virginia Supreme Court. APCo expects to submit its brief before the Virginia Supreme Court in the second or third quarter of 2021.

In April 2021, and in conjunction with APCo’s November 2020 and March 2021 appeals with the Virginia Supreme Court, APCo filed a petition for interim rates with the Virginia Supreme Court (subject to refund with interest and supported by a bond issuance) requesting a $40 million ~~expense~~increase in annual APCo Virginia base rates. APCo submitted this filing based on Virginia law that allows the Virginia Supreme Court to authorize interim rates until the final disposition on APCo’s appeals. APCo also requested an expedited schedule from the Virginia Supreme Court on APCo’s appeals.

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 appeals regarding treatment of the closed coal plants are granted by the Virginia Supreme Court, it could initially reduce future net income and impact financial condition.

•2020 Ohio Base Rate Case - In June 2020, OPCo filed a request with the PUCO for a $42 million annual increase in base rates based upon a proposed 10.15% ROE net of existing riders. In March 2021, OPCo, the PUCO staff and various intervenors filed a joint stipulation and settlement agreement with the PUCO based upon an annual revenue decrease of $68 million and an ROE of 9.7%. The difference between OPCo’s requested annual base rate increase and the agreed upon decrease is primarily due to a reduction in the requested ROE, the removal of proposed future energy efficiency costs and a decrease in vegetation management expenses moved to recovery in riders. In addition, the joint stipulation and settlement agreement includes an increased fixed monthly residential customer charge, the discontinuation of rate decoupling and the continuation of the DIR with annual revenue caps of $57 million in 2021, $91 million in 2022, $116 million in 2023 and $51 million for the first five months of 2024. Annual revenue caps for the DIR can be increased if OPCo achieves certain reliability standards. A hearing is scheduled with the PUCO in May 2021.

•Hurricane Laura - In August 2020, Hurricane Laura hit the coasts of Louisiana and Texas, causing power outages to more than 130,000 customers across SWEPCo’s service territories. Prior to Hurricane Laura, SWEPCo did not have a catastrophe reserve or automatic deferral authority within any of its jurisdictions. In October 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with ~~APCo’s Virginia~~Hurricane Laura. In October 2020, as part of the 2020 Texas Base Rate Case, SWEPCo requested deferral authority of incremental other operation and maintenance expenses. As of March 31, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $82 million ($79 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $31 million, all of which is related to the Louisiana jurisdiction. Management expects to request recovery of these storm costs in a filing inclusive of SWEPCo’s various other storm costs.

•2012 Texas Base Rate Case - 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. 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. The Texas Supreme Court’s opinion agrees with the PUCT’s judgment affirming the prudence of the Turk Plant.Motions for rehearing were due April 12, 2021 and no party filed a timely motion. As of March 31, 2021, the net book value of Turk Plant was $1.4 billion, before cost of removal, including materials and supplies inventory and CWIP. SWEPCo’s Texas jurisdictional ~~retired coal-fired plants, APCo estimates its Virginia earnings for~~share of the ~~triennial period to be below the authorized ROE range.~~Turk Plant investment is approximately 33%.

~~2012 Texas Base Rate Case~~ - 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. 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. SWEPCo’s Texas jurisdictional share of the Turk Plant investment is approximately 33%.

conspiracy involving the adoption of HB 6. Certain defendants in that case have since pleaded guilty. In August 2020, an AEP shareholder filed a putative class action lawsuit against AEP and certain of its officers for alleged violations of securities laws in connection with HB 6. In January and February 2021, two AEP shareholders filed two derivative actions purporting to assert claims on behalf of AEP against certain AEP officers and directors based on allegations similar to those in the putative securities class action. In April 2021, another similar derivative action asserting claims on behalf of AEP against certain AEP officers and directors was filed. See Litigation Related to Ohio House Bill 6 section of Litigation below for additional information.

In March 2021, the Governor of Ohio signed legislation that, among other things, rescinded the payments to the nonaffiliated owner of Ohio’s nuclear power plants that were previously authorized under HB 6. The new legislation, House Bill 128, goes into effect after 90 days and leaves unchanged other provisions of HB 6 regarding energy efficiency programs, recovery of renewable energy costs and recovery of OVEC costs. To the extent that OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030 or ~~fully recover energy efficiency~~incurs significant costs ~~through 2020~~associated with the securities class action or the derivative actions, it could reduce future net income and cash flows and impact financial condition.

~~In April 2020, the Virginia Clean Economy Act was signed into law by the Virginia Governor. The law will become effective July 2020 and includes requirements for Virginia electric utilities to:~~

•In April 2020, the Virginia Clean Economy Act was signed into law by the Virginia Governor and became effective in July 2020. The law includes the following requirements: (a) Virginia electric utilities to retire no later than 2045 all electric generating units located in Virginia that emit carbon as a by-product, (b) APCo to produce 100% of the company’s power to serve Virginia customers from renewable sources by 2050 with increasing percentages of mandatory renewable energy sources each year and (c) Virginia electric utilities to achieve increasing annual energy efficiency savings from 2022-2025 using 2019 as the base year. This law also provides that if the Virginia SCC finds in any triennial review that revenue reductions related to energy efficiency programs approved and deployed since the utility's previous triennial review have caused the utility to earn more than 70 basis points below its authorized rate of return, the Virginia SCC shall order increases to the utility's rates necessary to recover such revenue reductions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

•In December 2020, APCo and WPCo filed a proposal with the WVPSC to implement an investment tracker surcharge mechanism for recovering costs associated with capital investment made between base rate cases.The initial filing requests a total annual increase of $50 million ($41 million related to APCo), which represents recovery of costs associated with infrastructure investments made over an approximate three-year period since the companies’ last base rate case filing in 2018.The filing also proposes that APCo and WPCo could submit annual filings with requested increases capped to a percentage of total retail revenues (3.5% in the first year and 3% in subsequent filings with an overall cap of 9.5%). If a future base rate case is filed, the surcharge would reset to zero on implementation of the new rates. In January 2021, WVPSC staff filed a motion recommending that the WVPSC reject the proposal. The WVPSC deferred ruling on the staff motion and established a procedural schedule, which includes testimony from all parties to be received in May 2021 and a hearing is scheduled for June 2021. If APCo and WPCo do not receive approval to recover these incremental investments through the proposed tracker surcharge mechanism between base rate cases, it could cause a temporary reduction in future net income and cash flows and impact financial condition until APCo and WPCo can seek approval in their next base rate case.

•In April 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (NOPR) proposing to modify its incentive for transmission owners that join RTOs (RTO Incentive). Under the supplemental NOPR, the RTO Incentive would be modified such that a utility would only be eligible for the RTO Incentive for the first three years after the utility joins a FERC-approved Transmission Organization. This is a significant departure from a previous NOPR issued in 2020 seeking to increase the RTO Incentive from 50 basis points to 100 basis points. The supplemental NOPR also requires utilities that have received the RTO Incentive for three or more years to submit, within 30 days of the effective date of a final rule, a

compliance filing to eliminate the incentive from its tariff prospectively. The supplemental NOPR is subject to a 30 day comment period followed by a 15 day period for reply comments. A final rule is expected in the fourth quarter of 2021.

In 2019, the FERC approved settlement agreements establishing base ROEs of 9.85% (10.35% inclusive of RTO Incentive adder of 0.5%) and 10% (10.5% inclusive of RTO Incentive adder of 0.5%) for AEP’s PJM and SPP transmission-owning subsidiaries, respectively. In 2020, the FERC determined the base ROE for MISO’s transmission owning subsidiaries, should be 10.02% (10.52% inclusive of RTO Incentive adder of 0.5%).

If the FERC modifies its RTO Incentive policy, it would be applied, as applicable, to AEP’s PJM, SPP and MISO transmission owning subsidiaries on a prospective basis, and could affect future net income and cash flows and impact financial condition. Based on management’s preliminary estimates, if a final rule is adopted consistent with the April 2021 supplemental NOPR, it could reduce AEP’s pretax income by approximately $55 million to $70 million on an annual basis.

Utility Rates and Rate Proceedings

The Registrants file rate cases with their regulatory commissions in order to establish fair and appropriate electric service rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Registrants’ current and future results of operations, cash flows and financial position.

The following tables show the Registrants’ ~~completed and~~ pending base rate case proceedings in ~~2020.~~2021. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

Approved Revenue Approved New Rates
Company Jurisdiction Requirement Increase (Decrease) ROE Effective
(in millions)
I&M Indiana $ 77.4
(a) 9.7% March 2020
AEP Texas Texas (40.0 ) (b) 9.4% June 2020

Approved Revenue

Approved

New Rates

Company

Jurisdiction

Requirement Increase

ROE

Effective

(in millions)

KPCo

Kentucky

52.7

(a)

9.3%

January 2021

(a)See “2020 Kentucky Base Rate Case” section of Note 4 Rate Matters in the 2020 Annual Report for additional information.

Pending Base Rate Case Proceedings

(a)In March, 2021 a joint stipulation and settlement agreement was filed with the PUCO which included a $68 million decrease in base rates based upon an ROE of 9.7%.

(b)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.

(c)Staff and intervenor recommended base rate increases ranged from $20 million to $70 million.

(d)Awaiting procedural schedule.

Commission Staff/
Filing Requested Revenue Requested Intervenor Range of
Company Jurisdiction Date Requirement Increase ROE Recommended ROE
(in millions)
APCo Virginia March 2020 $ 64.9
9.9% (a)


~~(a)~~	~~Commission Staff/Intervenor direct testimony to be filed by August 2020.~~

Renewable Generation

The growth of AEP’s renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs.

Contracted Renewable Generation Facilities

AEP continues to develop its renewable portfolio within the Generation & Marketing segment. Activities include working directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies. The Generation & Marketing segment also develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties.

In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% interest in the 100 MW Dry Lake Solar Project located in southern Nevada for approximately $114 million. The transaction closed in the first quarter of 2021 and the solar project is expected to be in-service in the second quarter of 2021. See Note 6 - Acquisitions for additional information.

As of March 31, ~~2020,~~2021, subsidiaries within AEP’s Generation & Marketing segment had approximately ~~1,423~~1,549 MWs of contracted renewable generation projects in-service. In addition, as of March 31, ~~2020,~~2021, these subsidiaries had approximately ~~160~~239 MWs of renewable generation projects under construction with total estimated capital costs of ~~$235~~$349 million related to these projects.

Regulated Renewable Generation Facilities

In ~~July 2019,~~2020, PSO received approval from the OCC and SWEPCo ~~submitted filings before their respective commissions for~~received approval from the ~~approval~~APSC and LPSC to acquire the North Central Wind Energy Facilities, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. ~~Subject~~Both the APSC and LPSC approved the flex-up option, agreeing to ~~regulatory approval,~~acquire the Texas portion, which the PUCT denied. PSO will own 45.5% and SWEPCo will own 54.5% of the project, which will cost approximately $2 billion. ~~Two~~

In May 2020, the IRS issued a notice extending the “Continuity Safe Harbor” deadlines for qualifying renewable energy projects that began construction in 2016 and 2017 by one year as many projects are facing supply chain and other project development delays caused by COVID-19. Under the May 2020 IRS notice, qualifying renewable energy projects that began construction in 2016 and 2017 and which are placed in-service by the end of 2021 and 2022, respectively, will satisfy the Continuity Safe Harbor. Provided that each facility does satisfy the Continuity Safe Harbor, under the current IRS guidance, the 199 MW wind facility will qualify for 100% of the federal PTC, and the remaining two wind facilities, totaling 1,286 MWs, ~~would~~will qualify for 80% of the federal ~~PTC with year-end~~PTC.

In April 2021, ~~in-service dates. The third~~the 199 MW wind facility ~~(199 MWs) would qualify for 100%~~was acquired and placed in-service with an estimated investment of ~~the PTC with a year-end 2020~~$307 million. The 287 MW wind facility is targeted to be acquired and placed in-service ~~date. The acquisition can be scaled, subject to commercial limitation,~~

~~to align with individual state resource needs and approvals. In~~in December 2019, PSO reached a joint stipulation and settlement agreement with the OCC, Oklahoma Attorney General’s office and customer groups; the PSO agreement was approved by the Oklahoma Commission in February 2020. In January 2020, SWEPCo reached a joint settlement agreement with the APSC, Arkansas Attorney General’s office and Walmart, Inc. Hearings in the Texas proceeding took place in February 2020. In April 2020, SWEPCo reached a joint settlement agreement with Louisiana Staff, Walmart, Inc.2021 and the ~~Alliance~~999 MW wind facility is targeted to be acquired and placed in-service between December 2021 and April 2022. See Note 6 - Acquisitions for ~~Affordable Energy. In May 2020,~~additional information.

Strategic Evaluation of KPCo

AEP has initiated a strategic evaluation for its ownership in KPCo, a wholly-owned regulated generation, transmission and distribution utility with approximately 166,000 retail customers in eastern Kentucky. Potential alternatives may include continued ownership or a sale of KPCo. Management has not made a decision regarding the Arkansas Commission approved the settlement agreement as filed, with the exception that SWEPCo use its formula rate rider to recover its costs rather than the requested rider. SWEPCo is seeking regulatory approvals by July 2020.potential alternatives, but expects a decision will be made during 2021. As of March 31, 2021, KPCo has total assets of approximately $2.7 billion and total equity of approximately $837 million.

~~Hydroelectric Generation~~

~~Evaluating Sale of Hydroelectric Generation~~Racine

In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated party. As of March ~~2020, management placed 10 hydroelectric generation plants under study for a potential sale. The table below shows~~31, 2021, the net book value of ~~each plant, including CWIP~~Racine was $45 million. The sale of Racine requires approval from the FERC and ~~materials and supplies, before cost~~the U.S. Army Corps of ~~removal of the plants included~~Engineers. The sale is expected to close in the ~~study.~~second quarter of 2021 and result in an immaterial gain. Racine was not presented as Held for Sale on AEP’s balance sheets due to immateriality.

Owner Plant Name Units State Net Book Value as of March 31, 2020
Net Maximum
Capacity (MWs)
Year Plant or First Unit Commissioned
(in millions)
AGR Racine 2 OH $ 43.2
48
1982
APCo London 3 WV 9.6
14
1935
APCo Marmet 3 WV 11.0
14
1935
APCo Winfield 3 WV 13.9
15
1938
I&M Berrien Springs 12 MI 7.7
6
1908
I&M Buchanan 10 MI 5.1
3
1919
I&M Constantine 4 MI 2.6
1
1921
I&M Elkhart 3 IN 5.5
3
1913
I&M Mottville 4 MI 2.9
2
1923
I&M Twin Branch Hydro 8 IN 7.1
5
1904
Total $ 108.6
111

If management decides to proceed with the sale of these plants, FERC approval would be required. In addition, for all plants, except for Racine, state commission approval would be required. Management currently estimates that any potential sale of these plants would not be completed until late 2020 at the earliest. There is no assurance that management will be able to sell any of these plants.

Dolet Hills Power Station and Related Fuel Operations

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~~After careful consideration of current economic conditions, and particularly for the benefit of their customers, management of SWEPCo and CLECO determined ~~that~~ DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ~~management notified a substantial portion~~ceased extraction of ~~its workforce that employment will permanently end~~lignite at the mine in ~~June~~May 2020. Based on these actions, management ~~has~~ revised the estimated useful life of ~~many of~~ DHLC’s and Oxbow’s assets ~~to June 2020~~ to coincide with the date at which extraction was discontinued in the second quarter of 2020 and the date at which delivery of lignite is expected to ~~be discontinued.~~cease in September 2021. 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.~~mining.

The Dolet Hills Power Station costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Dolet Hills Power Station is ~~$151~~$150 million, including CWIP and materials and supplies, before cost of removal.

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~~fuel agreements, SWEPCo’s fuel inventory and ~~associated mining-related~~unbilled fuel costs from mining related activities were $126 million 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. As2021. Also, as of March 31, ~~2020, Oxbow has unbilled fixed costs~~2021, SWEPCo had a net over-recovered fuel balance of ~~$26~~$20 million, ~~that will be billed to SWEPCo prior to~~excluding impacts of the ~~closure of~~February 2021 severe winter weather event, which includes fuel consumed at 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.

In June 2020, SWEPCo filed a fuel reconciliation with the PUCT for its retail operations in Texas, including Dolet Hills, for the reconciliation period of March 1, 2017 to December 31, 2019. See “2020 Texas Fuel Reconciliation” section of Note 4 for additional information.

In October 2020, SWEPCo filed a request with the LPSC seeking approval to close the mines and to recover the Louisiana jurisdictional share of the additional fuel costs. 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 March 2021, the APSC approved fuel rates that provide recovery of the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

~~FERC Transmission ROE Methodology~~

Pirkey Power Plant and Related Fuel Operations

In November ~~2019,~~2020, management announced plans to retire the ~~FERC issued Opinion No. 569, which adopted~~Pirkey Power Plant in 2023. The Pirkey Power Plant costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Pirkey Power Plant is $209 million, including CWIP, before cost of removal. Sabine is a ~~revised methodology for determining whether~~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 ~~existing base ROE is just~~amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and ~~reasonable under Federal Power Act and determined~~operating costs, from Sabine to cease during the base ROE for MISO’s transmission-owning members should be reduced to 9.88% (10.38% inclusive of RTO incentive adder of 0.5%). The revised ROE methodology relies on two financial models, which include the discounted cash flow model and the capital asset pricing model, to establish a composite zone of reasonableness. In December 2019, AEP filed multiple requests for rehearing and participated in filing comments and requests for rehearing on behalf of transmission owners and industry organizations. Management believes FERC Opinion No. 569 reverses the expectation of a four-model framework proposed by FERC in 2018 and vetted widely in FERC 2019 Notice of Inquiry regarding base ROE policy. Management does not believe this ruling will have a material impact on financial results for its MISO transmission owning subsidiaries. In the secondfirst quarter of ~~2019, FERC approved settlement~~2023. Under the fuel agreements, ~~establishing base ROEs~~SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $163 millionas of ~~9.85% (10.35% inclusive~~March 31, 2021. Also, as of ~~RTO incentive adder~~March 31, 2021, SWEPCo had a net over-recovered fuel balance of ~~0.5%)~~$20 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Pirkey Power Plant. Additional operational costs are expected to be incurred by Sabine and ~~10% (10.5% inclusive~~billed to SWEPCo, as well as land-related costs incurred by SWEPCo, prior to the closure of ~~RTO incentive adder~~the Pirkey Power Plant and recovered through fuel clauses. If any of 0.5%) for AEP’s PJM and SPP transmission-owning subsidiaries, respectively. In March 2020, as a follow-up to its 2019 Notice of Inquiry regarding transmission incentives policy, FERC issued a Notice of Proposed Rulemaking and requested comments by July 2020. AEP will file comments and monitor this proceeding. If FERC makes any changes to its ROE and incentive policies, they would be applied to AEP’s PJM and SPP transmission owning subsidiaries on a prospective basis, andthese costs are not recoverable, it could ~~affect~~reduce future net income and cash flows and impact financial condition.

LITIGATION

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies for additional information.

Rockport Plant Litigation

In 2013, the Wilmington Trust Company filed a complaint in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.

claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit.

In 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion and judgment affirming the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims, reversing the district court’s dismissal of the breach of contract claims and remanding the case for further proceedings.

arguing that the consent decree violates the facility lease and the participation agreement and requesting that the district court enter a judgment for the plaintiffs on their breach of contract claim. AEP’s memorandum in opposition to plaintiffs’ motion for partial summary judgment was filed in October 2020. At the parties’ request, the district court stayed the case until April 19, 2021 to provide the parties ~~filed a joint proposed case schedule in February 2020.~~an opportunity to resolve the case. See ~~“Modification of~~“Obligations under the ~~NSR~~New Source Review Litigation Consent Decree” section below for additional information.

~~Management will continue~~On April 20, 2021, I&M and AEGCo reached an agreement to ~~defend against~~acquire 100% of the ~~claims. Given~~interests in Rockport Plant, Unit 2 for $115.5 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. As a result, the parties have submitted a stipulation and order of dismissal requesting that the district court ~~dismissed plaintiffs’~~dismiss the case without prejudice to plaintiffs asserting their claims ~~seeking compensatory relief~~in a re-filed action or in a new action. The agreement is subject to customary closing conditions, including regulatory approvals, and as ~~premature,~~of the closing will result in a final settlement of, and ~~that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management cannot determine a range~~release of ~~potential losses that is reasonably possible~~claims in, the lease litigation. Management believes its financial statements appropriately reflect the expected resolution of ~~occurring.~~the pending litigation.

~~Patent Infringement Complaint~~

Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula

The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula. The Claimants have asserted claims ~~that~~that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s ~~career;~~career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act ~~(ADEA);~~ and (c) the company failed to provide required notice regarding the changes to the Plan. AEP has responded to the Claimants providing a reasoned explanation for why each of their claims have been ~~denied, and the~~denied. The denial toof those claims ~~have been~~was appealed to the AEP System Retirement Plan Appeal ~~Committee.~~Committee and the Committee upheld the denial of claims. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that ~~are~~is reasonably possible of occurring.

Litigation Related to Ohio House Bill 6 (HB 6)

In August 2020, an AEP shareholder filed a putative class action lawsuit in the United States District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The amended complaint alleges misrepresentations or omissions by AEP regarding: (a) its alleged participation in or connection to public corruption with respect to the passage of HB 6 and (b) its regulatory, legislative, political contribution, 501 (c)(4) organization contribution and lobbying activities in Ohio. The complaint seeks monetary damages, among other forms of relief. The company will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

In January 2021, an AEP shareholder filed a derivative action in the United States District Court for the Southern District of Ohio purporting to assert claims on behalf of AEP against certain AEP officers and directors. In February 2021, a second AEP shareholder filed a similar derivative action in the Court of Common Pleas of Franklin County, Ohio. In April 2021, a third AEP shareholder filed a similar derivative action in the U.S. District Court for the Southern District of Ohio.These derivative complaints allege the officers and directors made misrepresentations and omissions similar to those alleged in the putative securities class action lawsuit filed against AEP. The derivative complaints together assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets, (c) unjust enrichment, (d) breach of duty for insider trading and (e) contribution for violations of sections 10(b) and 21D of the Securities Exchange Act of 1934; and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The company will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

On March 1, 2021, AEP received a litigation demand letter from counsel representing a purported AEP shareholder. The litigation demand letter is directed to the Board of Directors of AEP and contains factual allegations involving HB 6 that are generally consistent with those in the derivative litigation filed in state and federal court. The letter demands, among other things, that the AEP Board undertake an independent investigation into alleged legal violations by directors and officers, and that, following such investigation, the Company commence a civil action for breaches of fiduciary duty and related claims and take appropriate disciplinary action against those individuals who allegedly harmed the company. The AEP Board will act in response to the letter as appropriate. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

ENVIRONMENTAL ISSUES

AEP has a substantial capital investment program and incurs additional operational costs to comply with environmental control requirements. Additional investments and operational changes will be made in response to existing and anticipated requirements to reduce emissions from fossil generation and in response to rules governing the beneficial use and disposal of coal combustion by-products, clean water ~~rules~~ and renewal permits for certain water discharges.

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units. AEP, along with other parties, challenged ~~some~~a portion of the Federal EPA requirements. Management is engaged in the development of possible future requirements including the items discussed below. Management believes that further analysis and

better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If AEP cannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed below will have a material impact on AEP System generating units. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of March 31, ~~2020,~~2021, the AEP System ~~had~~owned generating capacity of approximately ~~25,500~~24,600 MWs, of which approximately ~~13,200~~12,100 MWs were coal-fired. Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on fossil generation. Based upon management estimates, AEP’s future investment to meet these existing and proposed requirements ranges from approximately ~~$500~~$350 million to ~~$1 billion~~$700 million through ~~2026.~~2027.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or revising certain existing requirements. The cost estimates will also change based on: (a) potential state rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors. In addition, management continues to evaluate the economic feasibility of environmental investments on regulated and competitive plants.

The table below represents the net book value before cost of removal, including related materials and supplies inventory, of plants or units of plants previously retired that have a remaining net book value as of March 31, 2020.

Generating Amounts Pending
Company Plant Name and Unit Capacity Regulatory Approval
(in MWs) (in millions)
APCo (a) Kanawha River Plant 400
$ 14.0
APCo (b) Clinch River Plant 705
25.3
APCo (a) Sporn Plant, Units 1 and 3 300
2.0
APCo (a) Glen Lyn Plant 335
3.4
SWEPCo (c) Welsh Plant, Unit 2 528
35.5
Total 2,268
$ 80.2


~~(a)~~	~~Remaining amounts pending regulatory approval represent the FERC and the West Virginia jurisdictional share.~~


~~(b)~~	APCo obtained permits following the Virginia SCC’s and WVPSC’s approval to convert Clinch River Plant, Units 1 and 2 to natural gas. In 2015, APCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. Clinch River Plant, Units 1 and 2 began operations as natural gas units in 2016.


~~(c)~~	~~Remaining amount pending regulatory approval represents the FERC and Louisiana jurisdictional share.~~

Management is seeking or will seek recovery of the remaining net book value in future rate proceedings. To the extent the net book value of these generation assets is not recoverable, it could materially reduce future net income and cash flows and impact financial condition.

~~Modification of~~Obligations under the New Source Review Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when they undertook various equipment repair and replacement projects over a period of nearly 20 years. The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO₂ and NO_xX emissions from the AEP System and various mitigation projects.

~~In 2017, AEP filed a motion with~~ The consent decree has been modified six times, for various reasons, most recently in 2020. All of the ~~district court seeking to modify~~environmental control equipment required by the consent decree to eliminate an obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. The other parties to the consent decree opposed AEP’s motion. The district court granted AEP’s request to delay the deadline to install Selective Catalytic Reduction (SCR) technology at Rockport Plant, Unit 2 until June 2020.

has been installed.

In May 2019, the parties filed a proposed order to modify the consent decree. The proposed order requires AEP to enhance the dry sorbent injection (DSI) system on both units at the Rockport Plant by the end of 2020, and meet 30-day rolling average emission rates for SO₂ ~~and NO~~_x ~~at the combined stack for the Rockport Plant beginning in 2021. Total SO~~₂ emissions from the Rockport Plant are limited to 10,000 tons per year beginning in 2021 and reduce to 5,000 tons per year when Rockport Plant, Unit 1 retires in 2028. The proposed modification was approved by the district court and became effective in July 2019. As part of the modification to the consent decree, I&M agreed to provide an additional $7.5 million to citizens’ groups and the states for environmental mitigation projects. As joint owners in the Rockport Plant, the $7.5 million payment was shared between AEGCo and I&M based on the joint ownership agreement.

In April 2020, an employee at the Rockport Plant was diagnosed with COVID-19. Several contract workers stopped working on the SCR project at Rockport Unit 2, and the project workforce reported an increased rate of absenteeism. I&M has notified the parties to the consent decree of this force majeure event and estimates that the date for completion of the SCR and DSI projects will be extended by approximately two weeks past the June 1, 2020 deadline. Management will continue to oversee the project through completion in light of these challenges.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (a) periodic revisions to NAAQS and the development of SIPs to achieve any more

stringent standards, (b) implementation of the regional haze program by the states and the Federal EPA, (c) regulation of hazardous air pollutant emissions under MATS, (d) implementation and review of CSAPR and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil generation under Section 111 of the CAA. Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

National Ambient Air Quality Standards

The Federal EPA issued new, more stringent NAAQS for PM in 2012 and ozone in 2015. The Federal EPA is currently reviewing both of these standards. A proposed rule to retain the existing PM standards was released in April 2020. The existing standards for NO₂ ~~and SO~~₂~~were retained after review by the Federal EPA in 2018 and 2019, respectively. Implementation of these standards is underway.~~

The Federal EPA ~~finalized non-attainment designations~~periodically reviews and revises the NAAQS for criteria pollutants under the ~~2015 ozone standard in 2018. The Federal EPA confirmed that for states included in~~CAA. Revisions tend to increase the ~~CSAPR program, there are no additional interstate transport obligations, as all areas~~stringency of the ~~country~~standards, which in turn may require AEP to make investments in pollution control equipment at existing generating units, or, since most units are ~~expected~~already well controlled, to ~~attain~~make changes in how units are dispatched and operated. Most recently, the ~~2008~~Biden administration has indicated that it is likely to revisit the NAAQS for ozone ~~standard before 2023. Challenges to the 2015 ozone standard~~ and ~~the Federal EPA’s determination that CSAPR satisfies certain states’ interstate transport obligations~~PM, which were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In August 2019, the court upheld the 2015 primary ozone standard, but remanded the secondary welfare-based standard for further review. The court vacated the Federal EPA’s determination that CSAPR fulfilled the states’ interstate transport obligations, because the Federal EPA’s modeling analysis did not demonstrate that all significant contributions would be eliminatedleft unchanged by the ~~attainment deadlines for downwind states. Any further changes will require additional rulemaking.~~prior administration following its review. Management cannot currently predict ~~the nature, stringency~~if any changes to either standard are likely or ~~timing of additional requirements for AEP’s facilities based on the outcome of these activities.~~what such changes may be, but will continue to monitor this issue and any future rulemakings.

Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR)~~, detailing how the CAA’s requirement that certain~~ in 2005, which could require power plants and other facilities to install best available retrofit technology ~~(BART) would~~to address regional haze in federal parks and other protected areas. ~~BART requirements apply to certain power plants.~~ CAVR ~~will be~~is implemented by the states, through SIPs, or by the Federal EPA, through FIPs. In 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs, including a provision that postpones the due date for the next comprehensive SIP revisions until 2021. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit.

~~The Federal EPA initially disapproved portions of the~~ Arkansas has an approved regional haze ~~SIP, but has approved a revised~~ SIP and all of SWEPCo's affected units are in compliance with the relevant requirements.

~~The~~In Texas, the Federal EPA ~~also~~ disapproved portions of the Texas regional haze ~~SIP. In 2017, the Federal EPA~~SIP and finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NO_xXregional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO₂ emissions trading program based on CSAPR allowance allocations. ~~A challenge~~Legal challenges to ~~the FIP was filed~~these various rulemakings are pending in both the U.S. Court of Appeals for the Fifth Circuit and the ~~case is pending~~U.S. Court of Appeals for the ~~Federal EPA’s reconsideration~~District of Columbia Circuit. Management cannot predict the final rule. In August 2018, the Federal EPA proposed to affirm its 2017 FIP approval. In November 2019, in response to comment, the Federal EPA proposed revisions to the intrastate trading program. Managementoutcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific ~~controls.~~controls and has intervened in the litigation in support of the Federal EPA.

Cross-State Air Pollution Rule

~~In 2011, the Federal EPA issued~~ CSAPR ~~as a replacement for the Clean Air Interstate Rule,~~is a regional trading program designed to address interstate transport of emissions that contributed significantly to downwind non-attainment with the 1997 ozone and PM NAAQS. CSAPR relies on SO₂ and NO_xX allowances and individual state budgets to compel further emission reductions from electric utility generating units. Interstate trading of allowances is allowed on a restricted sub-regional basis.

~~Petitions to review the CSAPR were filed in the U.S. Court of Appeals for the District of Columbia Circuit.~~ In ~~2015, the court found that~~January 2021, the Federal EPA ~~over-controlled~~finalized a revised CSAPR rule, which substantially reduces the SO₂ ~~and/or~~ozone season NO_xX budgets in 2021-2024. Management believes it can meet the requirements of ~~14 states. The court remanded~~ the rule ~~to the Federal EPA for revision consistent with the court’s opinion while CSAPR remained in place.~~

In 2016, the Federal EPA issued a final rule, the CSAPR Update, to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The CSAPR Update significantly reduced ozone season budgets in many states and discounted the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. In 2019, the appeals court remanded the CSAPR Update to the Federal EPA because it determined the Federal EPA had not properly considered the attainment dates for downwind areas in establishing its partial remedy, and should have considered whether there were available measures to control emissions from sources other than generating units. Any further changes to the CSAPR rule will require additional rulemaking.

~~Mercury and Other Hazardous Air Pollutants (HAPs) Regulation~~

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule established unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of non-mercury metals) and hydrogen chloride (as a surrogate for acid gases). In addition, the rule proposed work practice standards for controlling emissions of organic HAPs and dioxin/furans, with compliance required within three years. Management obtained administrative extensions for up to one year at several units to facilitate the installation of controls or to avoid a serious reliability problem.

~~In 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the 2012 final rule. Various intervenors filed petitions for further review~~ in the ~~U.S. Supreme Court.~~near term, and is evaluating its compliance options for later years, when the budgets are further reduced.

In 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The court remanded the MATS rule to the Federal EPA to consider costs in determining whether to regulate emissions of HAPs from power plants. In 2016, the Federal EPA issued a supplemental finding concluding that, after considering the costs of compliance, it was appropriate and necessary to regulate HAP emissions from coal and oil-fired units. Petitions for review of the Federal EPA’s determination were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In 2018, the Federal EPA released a revised finding that the costs of reducing HAP emissions to the level in the current rule exceed the benefits of those HAP emission reductions. The Federal EPA also determined that there are no significant changes in control technologies and the remaining risks associated with HAP emissions do not justify any more stringent standards. Therefore, the Federal EPA proposed to retain the current MATS standards without change. In April 2020, the Federal EPA released a final rule adopting the conclusions set forth in the proposal and retaining the existing MATS standards.

Climate Change, CO₂ Regulation and Energy Policy

~~In 2015, the Federal EPA published the final CO~~₂~~emissions standards for new, modified and reconstructed fossil generating units, and final guidelines for the development of state plans to regulate CO~~₂ ~~emissions from existing sources, known as the Clean Power Plan (CPP).~~

In 2016, the U.S. Supreme Court issued a stay of the final CPP, including all of the deadlines for submission of initial or final state plans until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review. In 2017, the President issued an Executive Order directing the Federal EPA to reconsider the CPP and the associated standards for new sources. The Federal EPA filed a motion to hold the challenges to the CPP in abeyance pending reconsideration. In September 2019, ~~following the Federal EPA’s repeal of the CPP and promulgation of a replacement rule, the Court of Appeals for the District of Columbia Circuit dismissed the challenges.~~

~~In July 2019, the Federal EPA finalized~~ the Affordable Clean Energy (ACE) rule ~~to replace the CPP with new emission guidelines for regulating CO~~₂ ~~from existing sources. ACE establishes~~established a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. ~~The final~~However, in January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE rule ~~applies~~and remanded it to ~~generating units that commenced construction prior~~the Federal EPA. Management is unable to January 2014, generate greater than 25 MWs, have a baseload rating above 250 MMBtu per hour and burn coal for more than 10% of the annual average heat input over the preceding three calendar years, with certain exceptions. States must establish standards of performance for each affected facility in terms of pounds of CO₂ emitted per MWh, based on certain heat rate improvement measures and the degree of emission reduction achievable through each applicable measure, together with consideration of certain site-specific factors and the unit’s remaining useful life. State plans are required to be submitted in 2022, andpredict how the Federal EPA ~~has up~~will respond to ~~two years to review and approve a plan or disapprove it and adopt a federal plan. The final ACE rule has been challenged in~~ the ~~courts.~~court’s remand.

In 2018, the Federal EPA filed a proposed rule revising the standards for new sources and determined that partial carbon capture and storage is not the best system of emission reduction because it is not available throughout the U.S. and is not cost-effective. That rule has not been finalized. Management continues to actively monitor these rulemaking activities.

While no federal regulatory requirements to reduce CO2 emissions are in place, AEP has taken action to reduce and offset CO₂ emissions from its generating fleet. AEP expects CO₂ emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions. In April 2020, Virginia enacted clean energy legislation to allow the state to participate in the Regional Greenhouse Gas Initiative, require the retirement of all fossil-fueled generation by 2045 and require 100% renewable energy to be provided to Virginia customers by 2050. Management is taking steps to comply with these requirements, including increasing wind and solar installations, purchasing renewable power and broadening AEP System’s portfolio of energy efficiency programs.

In ~~September 2019,~~February 2021, AEP announced new intermediate and long-term CO₂ emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. The intermediate goal is ~~a 70%~~an 80% reduction from 2000 CO₂ emission levels from AEP generating facilities by 2030; the long-term goal is ~~to surpass an 80% reduction of~~net-zero CO₂ emissions from AEP generating facilities ~~from 2000 levels~~ by 2050. AEP’s total estimated CO₂emissions in ~~2019~~2020 were approximately 5844 million metric tons, a ~~65%~~73% reduction from AEP’s 2000 CO₂ emissions. AEP has made significant progress in reducing CO₂ emissions from its power generation fleet and expects its emissions to continue to decline. ~~AEP’s aspirational emissions goal is zero CO~~₂ ~~emissions by 2050.~~ Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers.

~~Federal and state legislation or regulations that mandate limits on the emission of CO~~₂ ~~could result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs.~~ Excessive costs to comply with future legislation or regulations ~~might~~has led to the announcement of early plant closures and could force AEP to close ~~some~~additional coal-fired generation facilities ~~which could possibly lead~~earlier than their estimate useful life. If AEP is unable to ~~impairment~~recover the costs of ~~assets.~~its investments, it would reduce future net income and cash flows and impact financial condition.

Coal Combustion Residual ~~(CCR)~~ Rule

~~In 2015, the~~The Federal ~~EPA published a final~~EPA’s CCR rule ~~to regulate~~regulates the disposal and beneficial re-use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants. The rule applies to active CCR landfills and surface impoundments at operating electric utility or independent generation facilities. The rule imposes construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements to be implemented on a schedule spanning an approximate four-year implementation period. In 2018, some of AEP’s facilities were required to begin monitoring programs to determine if unacceptable groundwater impacts will trigger future corrective measures. Based on additional groundwater data, further studies to design and assess appropriate corrective measures have been undertaken at four facilities.

In a challenge to the final 2015 rule, the parties initially agreed to settle some of the issues. In 2018, the U.S. Court of Appeals for the District of Columbia Circuit addressed or dismissed the remaining issues in its decision vacating and remanding certain provisions of the 2015 rule. The provisions addressed by the court’s decision, including changes to the provisions for unlined impoundments and legacy sites, will be the subject of further rulemaking consistent with the court’s decision.

~~Prior to the court’s decision,~~August 2020, the Federal EPA ~~issued~~revised the ~~July 2018~~CCR rule to include a requirement that ~~modifies certain compliance deadlines~~unlined CCR storage ponds cease operations and ~~other requirements~~initiate closure by April 11, 2021. The revised rule provides two options that allow facilities to extend the date by which they must cease receipt of coal ash and close the ponds.

The first option provides an extension to cease receipt of CCR no later than October 15, 2023 for most units, and October 15, 2024 for a narrow subset of units; however, the Federal EPA’s grant of such an extension will be based upon a satisfactory demonstration of the need for additional time to develop alternative ash disposal capacity and will be limited to the soonest timeframe technically feasible to cease receipt of CCR. Additionally, each request must undergo formal review, including public comments, and be approved by the Federal EPA. AEP filed applications for additional time to develop alternative disposal capacity at the following plants:


Company	Plant Name and Unit	Generating Capacity	Net Book Value (a)			Projected Retirement Date
		(in MWs)	(in millions)
APCo	Amos	2,930	$	2,149.4		2040
APCo	Mountaineer	1,320	971.2			2040
SWEPCo	Flint Creek Plant	258	275.7			2038
KPCo	Mitchell Plant	780	599.9			2040
WPCo	Mitchell Plant	780	597.9			2040
AEGCo	Rockport Plant, Unit 1	655	242.2			2028
I&M	Rockport Plant, Unit 1	655	558.2		(b)	2028

(a)Net book value before cost of removal including CWIP and inventory.

(b)Amount includes a $186 million regulatory asset related to the retired Tanners Creek Plant. The IURC and MPSC authorized recovery of the Tanners Creek Plant regulatory asset over the useful life of Rockport Plant, Unit 1 in ~~the~~ 2015 ~~rule.~~ and 2014, respectively.

In December ~~2018, challengers~~2020, APCo filed requests with the Virginia SCC and WVPSC to obtain the regulatory approvals necessary to implement the compliance plans and seek recovery of the estimated $240 million investment for the Amos and Mountaineer plants. 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 the compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant. Within those requests, WPCo and KPCo also filed a ~~motion~~$25 million alternative with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.

The second option is a retirement option, which provides a generating facility an extended operating time without developing alternative CCR disposal. Under the retirement option, a generating facility would have until October 17, 2023 to cease operation and to close CCR storage ponds 40 acres or less in size, or through October 17, 2028 for ~~partial stay or vacatur of the July 2018 rule. On the same day,~~facilities with CCR storage ponds greater than 40 acres in size. Pursuant to this option, AEP informed the Federal EPA ~~filed a motion for partial remand~~ of its intent to retire the ~~July 2018 rule. The court granted~~Pirkey Power Plant and cease using coal at the ~~Federal EPA’s motion.~~ Welsh Plant:

Company

Plant Name and Unit

Generating
Capacity

Net Investment (a)

Accelerated Depreciation Regulatory Asset

Projected
Retirement Date

(in MWs)

(in millions)

SWEPCo

Pirkey Power Plant

580

178.3

30.8

2023 (b)

SWEPCo

Welsh Plants, Units 1 and 3

1,053

528.8

14.2

2028 (c)(d)

(a)Net book value including CWIP excluding cost of removal and materials and supplies.

(b)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.

(c)In November ~~2019,~~2020, management announced it will cease using coal at the ~~Federal EPA proposed revisions to implement~~Welsh Plant in 2028.

(d)Unit 1 is currently being recovered through 2027 in the ~~court’s decision regarding~~Louisiana jurisdiction and through 2037 in the ~~timing for closure of unlined surface impoundments along with impoundments not meeting~~Arkansas and Texas jurisdictions. Unit 3 is currently being recovered through 2032 in the ~~required distance from an aquifer. The comment period closed~~Louisiana jurisdiction and through 2042 in ~~January 2020. In December 2019,~~ the ~~Federal EPA proposed a federal permit program, implementing the Water Infrastructure Improvements for the Nation Act, that would apply in states that do not have an approved CCR program.~~Arkansas and Texas jurisdictions.

Other utilities and industrial sources have been engaged in litigation with environmental advocacy groups who claim that releases of contaminants from wells, CCR units, pipelines and other facilities to groundwaters that have a hydrologic connection to a surface water body represent an “unpermitted discharge” under the CWA. Two cases were accepted by the U.S. Supreme Court for further review of the scope of CWA jurisdiction. In April 2020, the Supreme Court issued an opinion remanding one of these cases to the Ninth Circuit based on its determination that discharges from an injection well that make their way to the Pacific Ocean through ground waterAEP may require a permit if the distance traveled through ground water, length of time to reach the surface water and other factors make it “functionally equivalent” to a direct discharge from a point source. The second case was also remanded to the lower court. Prior to the Supreme Court’s decision, the Federal EPA opened a rulemaking docket to solicit information to determine whether it should provide additional clarification of the scope of CWA permitting requirements for discharges to groundwater, and issued an interpretive statement finding that discharges to groundwater are not subject to NPDES

~~permitting requirements under the CWA. Management is unable to predict the impact of these developments on AEP’s facilities.~~

~~Because AEP currently uses surface impoundments and landfills to manage CCR materials at generating facilities,~~incur significant costs ~~will be incurred~~ to upgrade or close and replace ~~these existing facilities~~surface impoundments and landfills used to manage CCR and to conduct any required remedial actions. Under the retirement option above, AEP may need to recover remaining depreciation and estimated closure costs associated with retiring plants over a shorter period. If AEP cannot ultimately recover the costs of environmental compliance and/or the remaining depreciation and estimated closure costs associated with retiring plants in a timely manner, it would reduce future net income and cash flows and impact financial condition.

Closure and post-closure costs have been included in ARO in accordance with the requirements in the final rule. Additional ARO revisions will occur on a site-by-site basis if groundwater monitoring activities conclude that corrective actions are required to mitigate groundwater impacts, which could include costs to remove ash from some unlined units.

In March 2020, Virginia’s Governor signed House Bill 443 (HB 443) requiring APCo to close ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. APCo’s current ARO for these units is based on closure in place and will require future revision to reflect the costs of closure by removal. As of March 31, 2020, APCo is unable to reasonably estimate this cost. Management expects to record a material revision to the ARO after engineering plans for the removal are developed later in 2020. The closure is required to be completed within 15 years from the start of the excavation process. HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause (E-RAC). APCo may begin deferring incurred costs on July 1, 2020 and recovering these costs through the E-RAC beginning July 1, 2022. APCo is permitted to record carrying costs on the unrecovered balance of closure costs at a weighted average cost of capital approved by the Virginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered from Virginia jurisdictional customers through the E-RAC. Management does not expect HB 443 to materially impact results of operations or cash flows, but does anticipate a material impact to APCo’s balance sheet.

If removal of ash is required without providing similar assurances of cost recovery in regulated jurisdictions, it would impose significant additional operating costs on AEP, which could lead to increased financing costs and liquidity needs. Other units in Virginia, Ohio, West Virginia and Kentucky have already ~~have~~ been closed in place in accordance with state law programs. Management will continue to participate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units.

Clean Water Act Regulations

~~In 2014, the~~The Federal ~~EPA issued a final~~EPA’s ELG rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms impinged or entrained in the cooling water. The rule was upheld on review by the U.S. Court of Appeals for the Second Circuit. Compliance timeframes are established by the permit agency through each facility’s NPDES permit as those permits are renewed and have been incorporated into permits at several AEP facilities. Additional AEP facilities are reviewing these requirements as their wastewater discharge permits are renewed and making appropriate adjustments to their intake structures.

~~In 2015, the Federal EPA issued a final rule revising effluent limitation guidelines~~ for generating ~~facilities. The rule established~~facilities establishes limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are to ~~be imposed as soon as possible after November 2018 and no later than December 2023. These requirements would~~ be implemented through each facility’s wastewater discharge permit. ~~The~~A recent revision to the ELG rule, ~~was challenged~~published in ~~the U.S. Court~~October 2020, establishes additional options for reusing and discharging small volumes of ~~Appeals for the Fifth Circuit. In 2017, the Federal EPA announced its intent to reconsider and potentially revise the standards for FGD wastewater and~~ bottom ash transport ~~water. The Federal EPA postponed~~water, provides an exception for retiring units and extends the compliance ~~deadlines for those wastewater categories~~deadline to bea date as soon as possible beginning one year after the rule was published but no ~~earlier~~later than 2020, to allow for reconsideration. In April 2019, the Fifth Circuit vacated the standards for landfill leachate and legacy wastewater, and remanded them to the Federal EPA for reconsideration. In November 2019, the Federal EPA proposed revisions to the guidelines for existing generation facilities. The comment period ended in January 2020.December 2025. Management ~~is assessing~~has assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge ~~permitting.~~permitting for FGD wastewater and bottom ash transport water. Permit modifications for affected facilities were filed in January 2021 that reflect the outcome of that assessment.

Impact of Environmental Regulation on Coal-Fired Generation

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 may result in a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.

In ~~2015,~~addition to the November 2020 announcement related to the Federal ~~EPA~~EPA’s CCR rules, management also decided not to renew the Rockport Plant, Unit 2 lease when it expires in 2022. Previously, management retired or announced early closure plans for Welsh Unit 2, Oklaunion Power Station, Dolet Hills Power Station and Northeastern Plant Unit 3.

The table below summarizes the ~~U.S. Army Corps~~net book value, as of ~~Engineers jointly issued a final rule to clarify~~March 31, 2021, of generating facilities retired or planned for early retirement:


Company	Plant	Net Investment (a)		Accelerated Depreciation Regulatory Asset		Actual/Projected Retirement Date		Current Authorized Recovery Period	Annual Depreciation (b)
		(in millions)					(in millions)
SWEPCo	Dolet Hills Power Station	$	51.3	$	92.6	2021		(c)	$	7.7
PSO	Northeastern Plant, Unit 3	190.5		114.8		2026		(d)	14.9
PSO	Oklaunion Power Station	—		34.0		2020		(e)	0.4
SWEPCo	Pirkey Power Plant	178.3		30.8		2023		(f)	13.7
SWEPCo	Welsh Plant, Units 1 and 3	528.8		14.2		2028 (g)		(h)	33.3
SWEPCo	Welsh Plant, Unit 2	—		35.2		2016		(i)	—

(a)Net book value including CWIP excluding cost of removal and materials and supplies.

(b)These amounts represent the ~~scope~~amount of annual depreciation that has been collected from customers over the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. Various parties challenged the 2015 rule in different U.S. District Courts, which resulted in a patchwork of applicability of the 2015prior 12-month period.

rule and its predecessor. In December 2018, the Federal EPA and the U.S. Army Corps of Engineers proposed a replacement rule. In September 2019, the Federal EPA repealed the 2015 rule. The final replacement rule was published(c)Dolet Hills Power Station is currently being recovered through 2026 in the ~~Federal Register~~Louisiana jurisdiction and through 2046 in ~~April~~the Arkansas and Texas jurisdictions.

(d)Northeastern Plant, Unit 3 is currently being recovered through 2040.

(e)Oklaunion Power Station is currently being recovered through 2046.

(f)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.

(g)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.

(h)Welsh Plant, Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and ~~will become effective~~through 2037 in ~~June 2020. The final rule limits~~ the ~~scope~~Arkansas and Texas jurisdictions. Welsh Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

(i)Welsh Plant, Unit 2 is being recovered over the blended useful life of ~~CWA jurisdiction to four categories of waters,~~Welsh Plant, Units 1 and ~~clarifies exclusions for ground water, ephemeral streams, artificial ponds and waste treatment systems.~~3.

In April 2020, the U.S. District Court for the District of Montana issued a decision vacating the U.S. Army Corps of Engineers’ (Corps) General Nationwide Permit 12 (NWP 12), which provides standard conditions governing linear utility projects in streams, wetlands and other waters of the United States having minimal adverse environmental impacts. The Court found that in reissuing NWP 12 in 2017, the Corps failed to comply with Section 7 of the Endangered Species Act (ESA), which requires the Corps to consult with the U.S. Fish and Wildlife Service regarding potential impacts on endangered species. The Court remanded the permit back to the Corps to complete its ESA consultation, and also enjoined the Corps from authorizing any dredge or fill activities under NWP 12 pending completion of the consultation process. The Department of Justice filed a motion to stay the injunction and tailor the remedy imposed by the Court, and the court ordered the parties to file briefs on the issue in May 2020. Management is ~~monitoring~~seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the ~~litigation~~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, cash flows and ~~evaluating other permitting alternatives, but is currently unable to predict the~~ impact ~~of this decision on current and planned projects.~~

financial condition.

RESULTS OF OPERATIONS

SEGMENTS

AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

AEP’s reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

•Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

•Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.

•OPCo purchases energy and capacity at auction to serve ~~SSO~~standard service offer customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

•Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved ~~returns on equity.~~ROE.

•Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ~~returns on equity.~~ROE.

Generation & Marketing

~~Competitive generation in ERCOT and PJM.~~

•Contracted renewable energy investments and management services.

•Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP.

•Competitive generation in PJM.

The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

The following discussion of AEP’s results of operations by operating segment includes an analysis of Gross Margin, which is a non-GAAP financial measure. Gross Margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation as well as Purchased Electricity for Resale and Amortization of Generation Deferrals as presented in the ~~Registrants~~Registrants’ statements of income as applicable. Under the various state utility rate making processes, these expenses are generally reimbursable directly from and billed to customers. As a result, they do not typically impact Operating Income or Earnings Attributable to AEP Common Shareholders. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP’s financial performance in that it excludes the effect on Total Revenues caused by volatility in these expenses. Operating Income, which is presented in accordance with GAAP in AEP’s statements of income, is the most directly comparable GAAP financial measure to the presentation of Gross Margin. AEP’s definition of Gross Margin may not be directly comparable to similarly titled financial measures used by other companies.

The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:



	Three Months Ended March 31,
		2021		2020
		(in millions)
Vertically Integrated Utilities		$	270.4	$	245.3
Transmission and Distribution Utilities		114.4		116.2
AEP Transmission Holdco		172.0		140.6
Generation & Marketing		36.6		28.4
Corporate and Other		(18.4)		(35.3)
Earnings Attributable to AEP Common Shareholders		$	575.0	$	495.2

Three Months Ended March 31,
2020 2019
(in millions)
Vertically Integrated Utilities $ 245.3
$ 302.4
Transmission and Distribution Utilities 116.2
156.5
AEP Transmission Holdco 140.6
124.2
Generation & Marketing 28.4
40.1
Corporate and Other (35.3 ) (50.4 )
Earnings Attributable to AEP Common Shareholders $ 495.2
$ 572.8

First Quarter of ~~2020~~2021 Compared to First Quarter of ~~2019~~2020

Earnings Attributable to AEP Common Shareholders ~~decreased~~increased from ~~$573 million in 2019 to~~ $495 million in 2020 to $575 million in 2021 primarily due to:

~~A decrease~~•An increase in weather-related ~~usage.~~usage in the residential customer class.

~~A one-time reversal of a regulatory provision in 2019.~~

~~These decreases were partially offset by:~~

~~AEP’s results of operations by operating segment are discussed below.~~These increases were partially offset by:

•A decrease in usage in the commercial and industrial customer classes.

VERTICALLY INTEGRATED UTILITIES

Three Months Ended March 31,
Vertically Integrated Utilities 2020 2019
(in millions)
Revenues $ 2,226.7
$ 2,403.3
Fuel and Purchased Electricity 671.2
856.4
Gross Margin 1,555.5
1,546.9
Other Operation and Maintenance 691.3
690.1
Depreciation and Amortization 381.7
356.3
Taxes Other Than Income Taxes 117.1
116.0
Operating Income 365.4
384.5
Other Income 1.6
1.3
Allowance for Equity Funds Used During Construction 8.2
10.7
Non-Service Cost Components of Net Periodic Benefit Cost 16.9
17.0
Interest Expense (144.5 ) (139.0 )
Income Before Income Tax Expense (Benefit) and Equity Earnings 247.6
274.5
Income Tax Expense (Benefit) 2.1
(28.4 )
Equity Earnings of Unconsolidated Subsidiary 0.8
0.7
Net Income 246.3
303.6
Net Income Attributable to Noncontrolling Interests 1.0
1.2
Earnings Attributable to AEP Common Shareholders $ 245.3
$ 302.4

Summary of KWh Energy Sales for Vertically Integrated Utilities

(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.

Three Months Ended March 31,
2020 2019
(in millions of KWhs)
Retail:

Residential 8,262
9,216
Commercial 5,366
5,633
Industrial 8,475
8,545
Miscellaneous 530
546
Total Retail 22,633
23,940

Wholesale (a) 3,618
5,804

Total KWhs 26,251
29,744


~~(a)~~	~~Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.~~

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues. In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region.

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities


	Three Months Ended March 31,
	2021	2020
	(in degree days)
Eastern Region
Actual – Heating (a)	1,539	1,241
Normal – Heating (b)	1,600	1,611

Actual – Cooling (c)	3	13
Normal – Cooling (b)	4	5

Western Region
Actual – Heating (a)	958	649
Normal – Heating (b)	866	867

Actual – Cooling (c)	26	51
Normal – Cooling (b)	28	28

(a)Heating degree days are calculated on a 55 degree temperature base.

(b)Normal Heating/Cooling represents the thirty-year average of degree days.

(c)Cooling degree days are calculated on a 65 degree temperature base.

Three Months Ended March 31,
2020 2019
(in degree days)
Eastern Region

Actual – Heating (a)
1,241
1,571
Normal – Heating (b)
1,611
1,595

Actual – Cooling (c)
13
1
Normal – Cooling (b)
5
5

Western Region

Actual – Heating (a)
649
941
Normal – Heating (b)
867
866

Actual – Cooling (c)
51
11
Normal – Cooling (b)
28
28


~~(a)~~	~~Heating degree days are calculated on a 55 degree temperature base.~~


~~(b)~~	~~Normal Heating/Cooling represents the thirty-year average of degree days.~~


~~(c)~~	~~Cooling degree days are calculated on a 65 degree temperature base.~~

First Quarter of ~~2020~~2021 Compared to First Quarter of ~~2019~~2020


Reconciliation of First Quarter of 2020 to First Quarter of 2021
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)

First Quarter of 2020	$	245.3

Changes in Gross Margin:
Retail Margins	95.5
Margins from Off-system Sales	20.8
Transmission Revenues	10.3
Other Revenues	(3.8)
Total Change in Gross Margin	122.8

Changes in Expenses and Other:
Other Operation and Maintenance	(48.9)

Depreciation and Amortization	(50.4)
Taxes Other Than Income Taxes	(6.4)


Other Income	(0.9)
Allowance for Equity Funds Used During Construction	1.7
Non-Service Cost Components of Net Periodic Pension Cost	0.1
Interest Expense	4.9
Total Change in Expenses and Other	(99.9)

Income Tax Expense	2.3
Equity Earnings of Unconsolidated Subsidiary	(0.1)


First Quarter of 2021	$	270.4

Reconciliation of First Quarter of 2019 to First Quarter of 2020
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)

First Quarter of 2019 $ 302.4

Changes in Gross Margin:
Retail Margins 5.9
Margins from Off-system Sales (5.2 )
Transmission Revenues 6.1
Other Revenues 1.8
Total Change in Gross Margin 8.6

Changes in Expenses and Other:
Other Operation and Maintenance (1.2 )
Depreciation and Amortization (25.4 )
Taxes Other Than Income Taxes (1.1 )
Other Income 0.3
Allowance for Equity Funds Used During Construction (2.5 )
Non-Service Cost Components of Net Periodic Pension Cost (0.1 )
Interest Expense (5.5 )
Total Change in Expenses and Other (35.5 )

Income Tax Expense (30.5 )
Equity Earnings of Unconsolidated Subsidiary 0.1
Net Income Attributable to Noncontrolling Interests 0.2

First Quarter of 2020 $ 245.3

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:


•	~~Retail Margins~~ ~~increased $6~~ •Retail Margins increased $96 million ~~primarily due to the following:~~

~~A $25 million increase related to fuel at APCo and I&M,~~ primarily due to the ~~timing of recoverable PJM expenses. This increase was partially offset in other expense items below.~~following:

A $14 million increase due to the impact of the 2019 WVPSC order which required APCo and WPCo to offset Excess ADIT not subject to normalization requirements against the deferred fuel under-recovery balance in 2019.

~~The effect of rate proceedings in AEP’s service territories which included:~~


▪	~~A $14 million increase from rate proceedings at I&M. This increase was partially offset in other expense items below.~~


▪	~~An $11 million increase at PSO due to new base rates implemented in April 2019.~~


▪	~~An $11 million increase at SWEPCo primarily due to capital investment rider and base rate revenue increases in Texas, Arkansas and Louisiana.~~


▪	~~An $11 million increase at APCo and WPCo due to a base rate increase in West Virginia that was partially offset in Depreciation and Amortization expenses below.~~


▪	~~A $5 million increase at APCo and WPCo due to revenue primarily from rate riders in West Virginia.~~

~~A $9 million increase due to customer refunds related to the 2018 Tax Reform. This increase was partially offset in Income Tax Expense (Benefit) below.~~

~~These increases were partially offset by:~~

•A $61 million ~~decrease~~increase in weather-related usage primarily in the eastern region and primarily in the residential class.

•A $17 million increase in municipal and cooperative revenues at SWEPCo primarily due to the February 2021 severe winter weather event.

•A $15 million increase at KPCo due to rider revenues. This increase was partially offset in other expense items below.

•A ~~$28~~$14 million ~~decrease in weather-normalized retail margins~~increase at APCo and WPCo due to revenue from rate riders primarily in ~~the eastern region and primarily~~West Virginia. This increase was partially offset in ~~the commercial and industrial classes.~~other expense items below.

•A $7$2 million ~~decrease~~increase in revenue from rate riders at PSO. This ~~decrease~~increase was partially offset in other expense items below.


•	~~Margins from Off-system Sales~~ ~~decreased~~$5 million primarily due to WPCo’s historical merchant portion of Mitchell Plant moving to base rates beginning January 2020 and weaker market prices for energy in the RTOs which caused a significant decrease in sales volume.


•	~~Transmission Revenues~~ ~~increased $6 million primarily due to an increase in SPP transmission services revenue at SWEPCo.~~

~~Expenses and Other and Income Tax Expense~~•~~changed between years as follows:~~The effect of rate proceedings in AEP’s service territories which included:


•	~~Other Operation and Maintenance~~ ~~expenses increased $1 million primarily due to the following:~~

~~An $11~~•A $12 million increase at I&M due to ~~PJM transmission services including~~ the ~~annual formula~~Indiana and Michigan base rate ~~true-up.~~cases and rider revenues. This increase was partially offset in other expense items below.

•A $5$6 million increase at KPCo due to ~~SPP transmission services including the annual formula~~base rate ~~true-up.~~

~~A $3 million increase due to North Central Wind Energy Facilities expenses for SWEPCo and PSO.~~case revenues implemented in January 2021.

These increases were partially offset by:

•A $23 million decrease in weather-normalized retail margins driven by a $41 million decrease in the commercial and industrial customer classes partially offset by an $18 million increase in the residential customer class.

•A $16 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract at I&M.

•A $5 million decrease related to Tax Reform primarily due to an increase in customer refunds at KPCo. This decrease was partially offset in Income Tax Expense below.

•Margins from Off-system Sales increased$21 million primarily due to Turk Plant merchant sales as a result of the February 2021 severe winter weather event at SWEPCo.

•Transmission Revenues increased $10 million due to an increase in transmission investment.

•Other Revenues decreased $4 million primarily due to decreased pole attachment revenue at APCo and a decrease in rental revenue at WPCo and KPCo.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $49 million primarily due to the following:

•A $37 million increase in transmission services.

•A $16 million increase due to distribution reliability primarily related to vegetation management. This increase was offset in Gross Margin above.

•A $5 million increase due to storms primarily at KPCo, SWEPCo and I&M.

•A $4 million increase due to a decreased Nuclear Electric Insurance Limited distribution in 2021.

These increases were partially offset by:

•An $11 million decrease in employee-related expenses.

~~A $7~~•Depreciation and Amortization expenses increased $50 million ~~decrease~~primarily due to a higher depreciable base and an increase in depreciation rates at I&M. This increase was partially offset in Gross Margin above.

•Taxes Other Than Income Taxesincreased ~~Nuclear Electric Insurance Limited distribution~~$6 million primarily due to increased property taxes at SWEPCo resulting from the expiration of the Louisiana Industrial Tax Exemption related to the Stall Plant.

•Interest Expense decreased $5 million primarily due to a decrease in ~~2020.~~


•	~~Depreciation and Amortization~~interest rates on variable rate notes at I&M. ~~expenses increased $25 millionprimarily due to a higher depreciable base and increased depreciation rates approved at APCo, I&M and SWEPCo. This increase was partially offset in Retail Margins above.~~


•	~~Interest Expense~~ ~~increased $6 million primarily due to higher long-term debt balances at APCo.~~


•	~~Income TaxExpenseincreased~~$31 million primarily due to a decrease in amortization of Excess ADIT. The decrease in amortization of excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.

TRANSMISSION AND DISTRIBUTION UTILITIES


	Three Months Ended
	March 31,
Transmission and Distribution Utilities		2021		2020
		(in millions)
Revenues		$	1,088.1	$	1,106.9
Purchased Electricity		205.5		191.4

Gross Margin		882.6		915.5
Other Operation and Maintenance		365.2		367.2


Depreciation and Amortization		172.7		214.5
Taxes Other Than Income Taxes		157.6		146.2
Operating Income		187.1		187.6
Interest and Investment Income		0.4		0.7
Carrying Costs Income		0.5		0.4

Allowance for Equity Funds Used During Construction		6.8		7.0
Non-Service Cost Components of Net Periodic Benefit Cost		7.3		7.3
Interest Expense		(74.5)		(71.4)
Income Before Income Tax Expense		127.6		131.6
Income Tax Expense		13.2		15.4
Net Income		114.4		116.2
Net Income Attributable to Noncontrolling Interests		—		—
Earnings Attributable to AEP Common Shareholders		$	114.4	$	116.2

Three Months Ended March 31,
Transmission and Distribution Utilities 2020 2019
(in millions)
Revenues $ 1,106.9
$ 1,222.0
Purchased Electricity 191.4
229.7
Amortization of Generation Deferrals —
32.4
Gross Margin 915.5
959.9
Other Operation and Maintenance 367.2
405.9
Depreciation and Amortization 214.5
183.7
Taxes Other Than Income Taxes 146.2
145.5
Operating Income 187.6
224.8
Interest and Investment Income 0.7
1.3
Carrying Costs Income 0.4
0.2
Allowance for Equity Funds Used During Construction 7.0
6.9
Non-Service Cost Components of Net Periodic Benefit Cost 7.3
7.6
Interest Expense (71.4 ) (62.0 )
Income Before Income Tax Expense 131.6
178.8
Income Tax Expense 15.4
22.3
Net Income 116.2
156.5
Net Income Attributable to Noncontrolling Interests —
—
Earnings Attributable to AEP Common Shareholders $ 116.2
$ 156.5

Summary of KWh Energy Sales for Transmission and Distribution Utilities



	Three Months Ended March 31,
	2021	2020
	(in millions of KWhs)
Retail:
Residential	6,924	6,300
Commercial	5,576	5,873
Industrial	5,281	5,908
Miscellaneous	166	182
Total Retail (a)	17,947	18,263

Wholesale (b)	603	390

Total KWhs	18,550	18,653

Three Months Ended
March 31,
2020 2019
(in millions of KWhs)
Retail:

Residential 6,300
6,547
Commercial 5,873
5,618
Industrial 5,908
5,771
Miscellaneous 182
176
Total Retail (a) 18,263
18,112

Wholesale (b) 390
638

Total KWhs 18,653
18,750

(a)Represents energy delivered to distribution customers.

(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.

Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities



	Three Months Ended March 31,
	2021	2020
	(in degree days)
Eastern Region
Actual – Heating (a)	1,777	1,473
Normal – Heating (b)	1,883	1,898

Actual – Cooling (c)	—	3
Normal – Cooling (b)	3	3

Western Region
Actual – Heating (a)	315	91
Normal – Heating (b)	185	185

Actual – Cooling (d)	137	231
Normal – Cooling (b)	126	125

(a)Heating degree days are calculated on a 55 degree temperature base.

(b)Normal Heating/Cooling represents the thirty-year average of degree days.

(c)Eastern Region cooling degree days are calculated on a 65 degree temperature base.

(d)Western Region cooling degree days are calculated on a 70 degree temperature base.

Three Months Ended
March 31,
2020 2019
(in degree days)
Eastern Region

Actual – Heating (a)
1,473
1,892
Normal – Heating (b)
1,898
1,877

Actual – Cooling (c)
3
1
Normal – Cooling (b)
3
3

Western Region

Actual – Heating (a)
91
177
Normal – Heating (b)
185
187

Actual – Cooling (d)
231
122
Normal – Cooling (b)
125
123


~~(a)~~	~~Heating degree days are calculated on a 55 degree temperature base.~~


~~(b)~~	~~Normal Heating/Cooling represents the thirty-year average of degree days.~~


~~(c)~~	~~Eastern Region cooling degree days are calculated on a 65 degree temperature base.~~


~~(d)~~	~~Western Region cooling degree days are calculated on a 70 degree temperature base.~~

First Quarter of ~~2020~~2021 Compared to First Quarter of ~~2019~~2020


Reconciliation of First Quarter of 2020 to First Quarter of 2021
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)

First Quarter of 2020	$	116.2

Changes in Gross Margin:
Retail Margins	24.8
Margins from Off-system Sales	(37.4)
Transmission Revenues	12.4
Other Revenues	(32.7)
Total Change in Gross Margin	(32.9)

Changes in Expenses and Other:
Other Operation and Maintenance	2.0
Depreciation and Amortization	41.8
Taxes Other Than Income Taxes	(11.4)
Interest and Investment Income	(0.3)
Carrying Costs Income	0.1
Allowance for Equity Funds Used During Construction	(0.2)

Interest Expense	(3.1)
Total Change in Expenses and Other	28.9

Income Tax Expense	2.2

First Quarter of 2021	$	114.4

Reconciliation of First Quarter of 2019 to First Quarter of 2020
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)

First Quarter of 2019 $ 156.5

Changes in Gross Margin:
Retail Margins (74.2 )
Margins from Off-system Sales 0.7
Transmission Revenues 11.9
Other Revenues 17.2
Total Change in Gross Margin (44.4 )

Changes in Expenses and Other:
Other Operation and Maintenance 38.7
Depreciation and Amortization (30.8 )
Taxes Other Than Income Taxes (0.7 )
Interest and Investment Income (0.6 )
Carrying Costs Income 0.2
Allowance for Equity Funds Used During Construction 0.1
Non-Service Cost Components of Net Periodic Benefit Cost (0.3 )
Interest Expense (9.4 )
Total Change in Expenses and Other (2.8 )

Income Tax Expense 6.9

First Quarter of 2020 $ 116.2

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of purchased electricity ~~and amortization of generation deferrals~~ were as follows:


•	•Retail Margins increased $25 million primarily due to the following: • ~~decreased $74 million primarily due to the following:~~

A $58 million ~~decrease due to a reversal of a regulatory provision in Ohio in the first quarter of 2019.~~

~~A $39 million~~ net ~~decrease~~increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This ~~decrease~~increase was partially offset in Other Operation and Maintenance expenses below.

•A ~~$13~~$19 million increase in weather-related usage in Texas primarily due to a 246% increase in heating degree days, partially offset by a 41% decrease in ~~Ohio Deferred Asset Phase-In-Recovery Rider revenues which ended~~cooling degree days.

•A $10 million increase from interim rate increases driven by increased distribution investment in ~~the second quarter of 2019. This decrease was offset~~Texas.

•A $6 million increase in ~~Depreciation and Amortization expenses below.~~

~~A $7 million net decrease in margin in Ohio for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.~~

~~A $5 million decrease due to the OVEC PPA Rider which was replaced by~~ the Legacy Generation Resource Rider (LGRR). in Ohio. This ~~decrease~~increase was offset in Margins from Off-system Sales and Other Revenues below.

•A $4$6 million ~~decrease~~increase from interim rate increases driven by increased transmission investment in ~~weather-related usage in Texas primarily due to a 49% decrease in heating degree days, partially offset by an 89% increase in cooling degree days.~~Texas.

•A ~~$3 million decrease in revenues associated with a vegetation management rider in Ohio. This decrease was offset in Other Operation and Maintenance expenses below.~~

~~These decreases were partially offset by:~~

~~A $17~~$5 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.

•A ~~$13~~$5 million increase in revenues associated with a vegetation management rider in Ohio. This increase was partially offset in Other Operation and Maintenance expenses below.

These increases were partially offset by:

•A $27 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in Ohio in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.

•A $25 million decrease in weather-normalized margins in Texas primarily in the residential and commercial ~~classes in Texas.~~classes.

•A $7$16 million ~~increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.~~

~~A $7 million increase~~decrease in revenues in Ohio associated with the Universal Service Fund (USF). This ~~increase~~decrease was offset in Other Operation and Maintenance expenses below.

•A $15 million decrease due to refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform.

•Margins from Off-system Sales decreased $37 million primarily due to the following:

•A $7$30 million decrease in Texas due to lower Oklaunion Power Station PPA revenues. Oklaunion Power Station was retired in September 2020 and sold to a nonaffiliated third-party in October 2020. This decrease was partially offset in Depreciation and Amortization expenses below.

•A $14 million decrease in Ohio primarily due to unfavorable deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.

•Transmission Revenues increased $12 million primarily due to the following:

•A $19 million increase from interim rate increases driven by increased transmission investment in Texas.

This increase was partially offset by:

•A $4 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease was offset in Other Revenues below.

•Other Revenues decreased $33 million primarily due to the following:

•A $46 million decrease in securitization revenues primarily due to the ~~Transmission Cost Recovery Factor revenue rider~~AEP Texas Central Transition Funding II LLC bonds that matured in ~~Texas.~~

~~A $3 million increase in Ohio Energy Efficiency/Peak Demand Reduction rider revenues.~~July 2020. This ~~increase~~decrease was offset ~~in Other Operation and Maintenance expenses below.~~


•	~~Transmission Revenues~~ ~~increased $12 million primarily due to recovery of increased transmission investment in ERCOT.~~


•	~~Other Revenues~~ ~~increased $17 million primarily due to the following:~~

~~A $12 million increase primarily due to securitization revenue in Texas. This increase was offset below~~ in Depreciation and Amortization expenses and in Interest ~~Expense.~~Expense below.

~~A $4~~This decrease was partially offset by:

•An $8 million increase in revenues due to the amortization of a provision for refund recorded as part of the most recent base rate case in Texas. This increase was partially offset in Retail Margins and Transmission Revenues above.

•A $6 million increase primarily due to third-party LGRR revenue related to the recovery of OVEC ~~costs.~~costs in Ohio. This increase was offset in Retail Margins and Margins from Off-system Sales above.

Expenses and Other ~~and~~ ~~Income Tax Expense~~ changed between years as follows:


•	•Other Operation and Maintenance expenses decreased $2 million primarily due to the following: • ~~expenses decreased $39 million primarily due to the following:~~

A ~~$40~~$22 million decrease in ~~PJM~~energy efficiency/demand side management expenses ~~that were fully recovered~~ in ~~rate riders/trackers~~Ohio. This decrease was partially offset in Retail Margins above.

•A $20 million decrease in Texas due to lower Oklaunion Power Station PPA expenses. Oklaunion Power Station was retired in September 2020 and sold to a nonaffiliated third-party in October 2020. This decrease was offset in Gross Margin above.

•A $6$16 million decrease ~~in PJM expenses primarily related to the annual formula rate true-up.~~

~~These decreases were partially offset by:~~

~~An $8 million increase in distribution-related expenses.~~

~~A $7 million increase~~ in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset in Retail Margins above.

•A $7 million decrease in factored Customers Accounts Receivable expenses in Ohio primarily due to a current year adjustment to allowance for doubtful accounts.

These decreases were partially offset by:

•A $61 million increase in transmission expenses primarily due to an increase in PJM recoverable expenses. This increase was offset in Gross Margin above.

•A $5 million increase in recoverable distribution expenses in Ohio primarily related to vegetation management. This increase was offset in Retail Margins above.


•	•Depreciation and Amortization expenses decreased $42 million primarily due to the following: • ~~expenses increased $31 million primarily due to the following:~~

A ~~$15~~$44 million decrease in securitization amortizations in Texas related primarily to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. The securitization decrease was offset in Other Revenues above.

•A $16 million decrease in depreciation expense due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset above in Margins from Off-system Sales and Other Operation and Maintenance expenses.

These decreases were partially offset by:

•A $16 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.

~~A $12~~

•Taxes Other Than Income Taxes increased $11 million ~~increase in securitization amortizations in Texas. This increase was offset in Other Revenues above and in Interest Expense below.~~

~~A $5 million increase~~primarily due to ~~lower deferred equity amortizations associated with the Deferred Asset Phase-In-Recovery Rider~~increased property taxes driven by additional investments in ~~Ohio which ended in the second quarter of 2019.~~transmission and distribution assets and higher tax rates.

~~A $5~~•Interest Expense increased $3 million ~~increase in Ohio recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.~~primarily due to higher long-term debt balances.

~~These increases were partially offset by:~~

~~A $10 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.~~


•	~~Interest Expense~~ ~~increased $9 million primarily due to higher long-term debt balances.~~


•	~~Income Tax Expense~~ decreased $7 million due to a decrease in pretax book income, partially offset by a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset in Retail Margins above.

AEP TRANSMISSION HOLDCO


	Three Months Ended
	March 31,
AEP Transmission Holdco		2021		2020
		(in millions)
Transmission Revenues		$	377.0	$	310.2
Other Operation and Maintenance		27.2		29.9
Depreciation and Amortization		72.7		58.1
Taxes Other Than Income Taxes		59.2		51.9
Operating Income		217.9		170.3
Interest and Investment Income		0.2		0.9


Allowance for Equity Funds Used During Construction		16.7		16.2
Non-Service Cost Components of Net Periodic Benefit Cost		0.5		0.5
Interest Expense		(35.3)		(30.8)
Income Before Income Tax Expense and Equity Earnings		200.0		157.1
Income Tax Expense		45.8		38.4
Equity Earnings of Unconsolidated Subsidiary		19.0		22.9
Net Income		173.2		141.6
Net Income Attributable to Noncontrolling Interests		1.2		1.0
Earnings Attributable to AEP Common Shareholders		$	172.0	$	140.6

Three Months Ended March 31,
AEP Transmission Holdco 2020 2019
(in millions)
Transmission Revenues $ 310.2
$ 256.4
Other Operation and Maintenance 29.9
22.3
Depreciation and Amortization 58.1
41.8
Taxes Other Than Income Taxes 51.9
42.6
Operating Income 170.3
149.7
Interest and Investment Income 0.9
0.7
Allowance for Equity Funds Used During Construction 16.2
11.3
Non-Service Cost Components of Net Periodic Benefit Cost 0.5
0.6
Interest Expense (30.8 ) (23.0 )
Income Before Income Tax Expense and Equity Earnings 157.1
139.3
Income Tax Expense 38.4
31.9
Equity Earnings of Unconsolidated Subsidiary 22.9
17.8
Net Income 141.6
125.2
Net Income Attributable to Noncontrolling Interests 1.0
1.0
Earnings Attributable to AEP Common Shareholders $ 140.6
$ 124.2

Summary of Investment in Transmission Assets for AEP Transmission Holdco


	March 31,
	2021		2020
	(in millions)
Plant in Service	$	10,549.3	$	9,086.6
Construction Work in Progress	1,635.9		1,576.3
Accumulated Depreciation and Amortization	648.1		464.0
Total Transmission Property, Net	$	11,537.1	$	10,198.9

As of March 31,
2020 2019
(in millions)
Plant in Service $ 9,086.6
$ 7,073.6
Construction Work in Progress 1,576.3
1,899.6
Accumulated Depreciation and Amortization 464.0
318.8
Total Transmission Property, Net $ 10,198.9
$ 8,654.4

First Quarter of ~~2020~~2021 Compared to First Quarter of ~~2019~~2020

Reconciliation of First Quarter of ~~2019~~2020 to First Quarter of ~~2020~~2021

Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco

(in millions)


First Quarter of 2020	$	140.6

Changes in Transmission Revenues:
Transmission Revenues	66.8
Total Change in Transmission Revenues	66.8

Changes in Expenses and Other:
Other Operation and Maintenance	2.7
Depreciation and Amortization	(14.6)
Taxes Other Than Income Taxes	(7.3)
Interest and Investment Income	(0.7)

Allowance for Equity Funds Used During Construction	0.5

Interest Expense	(4.5)
Total Change in Expenses and Other	(23.9)

Income Tax Expense	(7.4)
Equity Earnings of Unconsolidated Subsidiary	(3.9)
Net Income Attributable to Noncontrolling Interests	(0.2)

First Quarter of 2021	$	172.0

First Quarter of 2019 $ 124.2

Changes in Transmission Revenues:
Transmission Revenues 53.8
Total Change in Transmission Revenues 53.8

Changes in Expenses and Other:
Other Operation and Maintenance (7.6 )
Depreciation and Amortization (16.3 )
Taxes Other Than Income Taxes (9.3 )
Other Income 0.2
Allowance for Equity Funds Used During Construction 4.9
Non-Service Cost Components of Net Periodic Pension Cost (0.1 )
Interest Expense (7.8 )
Total Change in Expenses and Other (36.0 )

Income Tax Expense (6.5 )
Equity Earnings of Unconsolidated Subsidiary 5.1

First Quarter of 2020 $ 140.6

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:


•	•Transmission Revenues increased $67 million primarily due to continued investment in transmission assets. ~~increased $54 million primarily due to continued investment in transmission assets.~~

Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiary changed between years as follows:


•	~~Other Operation and Maintenance~~ ~~expenses~~ ~~increased~~ $8 •Depreciation and Amortization expenses increased $15 million primarily due to a higher depreciable base. •Taxes Other Than Income Taxes increased $7 million primarily ~~due to the following:~~

~~A $3 million increase due to employee-related expenses.~~

~~A $2 million increase~~ due to higher ~~rent expense.~~property taxes as a result of increased transmission investment.

~~A $2~~•Interest Expense increased $5 million ~~increase~~primarily due to ~~continued investment in transmission assets.~~higher long-term debt balances.


•	~~Depreciation and Amortization~~ ~~expenses increased $16~~ •Income Tax Expense increased $7 million primarily ~~due to a higher depreciable base.~~


•	~~Taxes Other Than Income Taxes~~ ~~increased $9 million primarily due to higher property taxes as a result of increased transmission investment.~~


•	~~Allowance for Equity Funds Used During Construction~~ ~~increased $5 million primarily due to the following:~~

~~A $9 million increase~~ due to ~~prior year FERC audit findings.~~an increase in pretax book income.

~~This increase was partially offset by:~~

~~A $5~~•Equity Earnings of Unconsolidated Subsidiary decreased $4 million ~~decrease~~primarily due to ~~a decrease in CWIP.~~


•	~~Interest Expense~~ ~~increased $8 million primarily due to higher long-term debt balances.~~


•	~~Income Tax Expense~~ ~~increased $7 million primarily due to higher pretax book income.~~


•	~~Equity Earnings of Unconsolidated Subsidiaryincreased~~ ~~$5 million primarily due to higher pretax equity earnings at~~lower pretax equity earnings for PATH-WV.

GENERATION & MARKETING


	Three Months Ended
	March 31,
Generation & Marketing		2021		2020
		(in millions)
Revenues		$	634.2	$	438.6
Fuel, Purchased Electricity and Other		565.9		360.3

Gross Margin		68.3		78.3
Other Operation and Maintenance		28.2		41.4


Depreciation and Amortization		18.6		17.7
Taxes Other Than Income Taxes		2.6		3.4
Operating Income		18.9		15.8
Interest and Investment Income		0.5		1.0

Non-Service Cost Components of Net Periodic Benefit Cost		3.8		3.9
Interest Expense		(3.3)		(8.5)
Income Before Income Tax Benefit and Equity Earnings		19.9		12.2
Income Tax Benefit		(15.1)		(12.4)
Equity Earnings of Unconsolidated Subsidiaries		3.2		5.9
Net Income		38.2		30.5
Net Earnings Attributable to Noncontrolling Interests		1.6		2.1
Earnings Attributable to AEP Common Shareholders		$	36.6	$	28.4

Three Months Ended March 31,
Generation & Marketing 2020 2019
(in millions)
Revenues $ 438.6
$ 481.8
Fuel, Purchased Electricity and Other 360.3
383.3
Gross Margin 78.3
98.5
Other Operation and Maintenance 41.4
50.6
Depreciation and Amortization 17.7
12.9
Taxes Other Than Income Taxes 3.4
3.8
Operating Income 15.8
31.2
Interest and Investment Income 1.0
2.3
Non-Service Cost Components of Net Periodic Benefit Cost 3.9
3.7
Interest Expense (8.5 ) (3.8 )
Income Before Income Tax Benefit and Equity Earnings 12.2
33.4
Income Tax Benefit (12.4 ) (5.8 )
Equity Earnings of Unconsolidated Subsidiaries 5.9
—
Net Income 30.5
39.2
Net Earnings (Loss) Attributable to Noncontrolling Interests 2.1
(0.9 )
Earnings Attributable to AEP Common Shareholders $ 28.4
$ 40.1

Summary of MWhs Generated for Generation & Marketing


	Three Months Ended March 31,
	2021	2020
	(in millions of MWhs)
Fuel Type:
Coal	1	1
Renewables	1	1

Total MWhs	2	2

Three Months Ended
March 31,
2020 2019
(in millions of MWhs)
Fuel Type:

Coal 1
1
Renewables 1
—
Total MWhs 2
1

First Quarter of ~~2020~~2021 Compared to First Quarter of ~~2019~~2020


Reconciliation of First Quarter of 2020 to First Quarter of 2021
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)

First Quarter of 2020	$	28.4

Changes in Gross Margin:
Merchant Generation	4.0
Renewable Generation	5.3
Retail, Trading and Marketing	(19.3)
Total Change in Gross Margin	(10.0)

Changes in Expenses and Other:
Other Operation and Maintenance	13.2


Depreciation and Amortization	(0.9)
Taxes Other Than Income Taxes	0.8
Interest and Investment Income	(0.5)


Non-Service Cost Components of Net Periodic Benefit Cost	(0.1)
Interest Expense	5.2
Total Change in Expenses and Other	17.7

Income Tax Expense	2.7
Equity Earnings of Unconsolidated Subsidiaries	(2.7)
Net Earnings Attributable to Noncontrolling Interests	0.5

First Quarter of 2021	$	36.6

Reconciliation of First Quarter of 2019 to First Quarter of 2020
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)

First Quarter of 2019 $ 40.1

Changes in Gross Margin:
Merchant Generation (37.4 )
Renewable Generation 13.3
Retail, Trading and Marketing 3.9
Total Change in Gross Margin (20.2 )

Changes in Expenses and Other:
Other Operation and Maintenance 9.2
Depreciation and Amortization (4.8 )
Taxes Other Than Income Taxes 0.4
Interest and Investment Income (1.3 )
Non-Service Cost Components of Net Periodic Benefit Cost 0.2
Interest Expense (4.7 )
Total Change in Expenses and Other (1.0 )

Income Tax Benefit 6.6
Equity Earnings of Unconsolidated Subsidiaries 5.9
Net Earnings (Loss) Attributable to Noncontrolling Interests (3.0 )

First Quarter of 2020 $ 28.4

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost of service for retail operations were as follows:

•

•Merchant Generation increased $4 million primarily due to lower PPA expenses resulting from the retirement of the Oklaunion Power Station.

•Renewable Generation increased $5 million primarily due to higher market revenues from wind assets in the ERCOT region.

•Retail, Trading and Marketing decreased $19 million due to lower trading and retail margins due to unprecedented cold temperatures and record market prices in February 2021.

~~decreased $37 million primarily due to lower energy margins in 2020 and a reduction in revenues related to the retirement of Conesville Units 5 and 6 in 2019.~~


•	~~Renewable Generation~~ ~~increased $13 million primarily due to the acquisition of Sempra Renewables LLC and new projects placed in-service.~~


•	~~Retail, Trading and Marketing~~ ~~increased $4 million due to higher retail margins partially offset by lower trading and marketing activity.~~

Expenses and Other ~~Income Tax Benefit and Equity Earnings of Unconsolidated Subsidiaries~~ changed between years as follows:

•

•Other Operation and Maintenance expenses decreased $13 million primarily due to the following:

•An $8 million decrease due the retirement of Conesville Plant Unit 4 in 2020.

•A $6 million decrease due to gains recorded on the sale of land.

•Interest Expense decreased $5 million due to lower borrowing costs in 2021.

expenses decreased $9 million primarily due to the retirement of Conesville Units 5 and 6 in 2019 partially offset by expenses related to increased investments in wind farms and other renewable energy sources.


•	~~Depreciation and Amortization~~ ~~expenses increased $5 million due to a higher depreciable base from increased investments in renewable energy sources.~~


•	~~Interest Expense~~ ~~increased $5 million primarily due to increased borrowing costs related to the Sempra Renewables LLC acquisition.~~


•	~~Income Tax Benefit~~ ~~increased $7 million primarily due to a decrease in pretax book income and an increase in PTC.~~


•	~~Equity Earnings of Unconsolidated Subsidiaries~~ ~~increased $6 million primarily due to the Sempra Renewables LLC acquisition.~~

CORPORATE AND OTHER

First Quarter of ~~2020~~2021 Compared to First Quarter of ~~2019~~2020

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of ~~$50~~$35 million in ~~2019~~2020 to a loss of ~~$35~~$18 million in ~~2020~~2021 primarily due to:

•A ~~$22~~$17 million unrealized gain from an investment in ChargePoint.

•A $12 million decrease in ~~income tax expense due to a decrease~~interest expense.

•A $6 million increase in ~~consolidating tax adjustments and discrete items recorded in 2019.~~equity earnings.

~~A $13 million decrease in general corporate expenses.~~

~~A $5 million write-off of an equity investment and related assets in 2019.~~

These items were partially offset by:

•A ~~$14~~$9 million ~~decrease~~increase in ~~interest income due to a lower return on investments held by EIS.~~general corporate expenses.

•An ~~$11~~$8 million increase in ~~interest expense as~~Income Tax Expense due to an increase in pretax income and the recognition of a ~~result of increased debt outstanding.~~$4 million prior period adjustment in 2021.

AEP SYSTEM INCOME TAXES

First Quarter of ~~2020~~2021 Compared to First Quarter of ~~2019~~2020

Income Tax Expense increased $2$8 million primarily due to ~~a decrease in amortization of Excess ADIT. This~~an increase ~~is partially offset by a decrease~~ in pretax book income ~~and~~partially offset with an increase in ~~PTC.~~production tax credits.

FINANCIAL CONDITION

AEP measures financial condition by the strength of its balance ~~sheet~~sheets and the liquidity provided by its cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization


	March 31, 2021				December 31, 2020
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	32,345.0	57.1	%	$	31,072.5	57.2	%
Short-term Debt	3,048.4		5.4		2,479.3		4.6
Total Debt	35,393.4		62.5		33,551.8		61.8
AEP Common Equity	20,972.8		37.1		20,550.9		37.8
Noncontrolling Interests	247.2		0.4		223.6		0.4
Total Debt and Equity Capitalization	$	56,613.4	100.0	%	$	54,326.3	100.0	%

March 31, 2020 December 31, 2019
(dollars in millions)
Long-term Debt, including amounts due within one year $ 27,892.7
53.3 % $ 26,725.5
54.1 %
Short-term Debt 4,464.1
8.5
2,838.3
5.7
Total Debt 32,356.8
61.8
29,563.8
59.8
AEP Common Equity 19,728.4
37.7
19,632.2
39.6
Noncontrolling Interests 279.3
0.5
281.0
0.6
Total Debt and Equity Capitalization $ 52,364.5
100.0 % $ 49,477.0
100.0 %

AEP’s ratio of debt-to-total capital increased from ~~59.8%~~61.8% as of December 31, ~~2019~~2020 to ~~61.8%~~62.5% as of March 31, ~~2020~~2021 primarily due to an increase in ~~short-term~~ debt to ~~enhance liquidity as a result of volatility~~help address the cash flow implications resulting from the February 2021 severe winter weather event in ~~the capital markets.~~addition to supporting distribution, transmission and renewable investment growth.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability. Management believes AEP has adequate liquidity under its existing credit facilities. As of March 31, ~~2020,~~2021, AEP had ~~a $4~~$5 billion of revolving credit ~~facility~~facilities to support its commercial paper program. Additional liquidity is available from cash from operations and a receivables securitization agreement. Management is committed to maintaining adequate liquidity. AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, leasing agreements, hybrid securities or common stock. ~~There was increased volatility in the capital markets during the first quarter of 2020~~

In February 2021, severe winter weather impacted certain AEP service territories resulting in ~~higher commercial paper cost and limited access. To address these issues and the uncertainty around COVID-19, in~~disruptions to SPP market conditions. In March ~~2020,~~2021, AEP entered into a ~~$1 billion~~$500 million 364-day Term Loan and borrowed the full ~~amount.~~amount to help address the cash flow implications resulting from the February 2021 severe winter weather event. See Note 4 - Rate Matters for additional information.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of March 31, ~~2020,~~2021, available liquidity was approximately ~~$2.8~~$3.4 billion as illustrated in the table below:

Amount

Maturity

Commercial Paper Backup:

(in millions)

Revolving Credit Facility

4,000.0

March 2026

Revolving Credit Facility

1,000.0

March 2023

364-Day Term Loan

500.0

March 2022

Cash and Cash Equivalents

273.2

Total Liquidity Sources

5,773.2

Less:

AEP Commercial Paper Outstanding

1,874.4

364-Day Term Loan

500.0

Net Available Liquidity

3,398.8

Amount
Maturity
Commercial Paper Backup: (in millions)

Revolving Credit Facility $ 4,000.0

June 2022
364-Day Term Loan 1,000.0
March 2021
Cash and Cash Equivalents 1,554.6

Total Liquidity Sources 6,554.6

Less: AEP Commercial Paper Outstanding 2,709.6

364-Day Term Loan 1,000.0

Net Available Liquidity $ 2,845.0

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers. The maximum amount of commercial paper outstanding during the first three months of ~~2020~~2021 was $3$2 billion. The weighted-average interest rate for AEP’s commercial paper during ~~2020~~2021 was ~~2.06%~~0.24%.

Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling ~~$405~~$425 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, ~~2020~~2021 was ~~$241~~$183 million with maturities ranging from April ~~2020~~2021 to March ~~2021~~.2022.

Securitized Accounts Receivables

AEP’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in ~~July 2021.~~September 2022.

In March 2021, AEP Credit amended its receivables securitization agreement to extend trigger levels established in October 2020 and to also provide a step down approach to these levels as management continues to monitor the accounts receivable balances across the affiliated utility subsidiaries in response to the COVID-19 pandemic. As of March 31, 2021, the affiliated utility subsidiaries are in compliance with all requirements under the agreement. To the extent that an affiliated utility subsidiary is deemed ineligible under the agreement, the affiliated utility subsidiary would no longer participate in the receivables securitization agreement and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity.

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements. Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of March 31, ~~2020,~~2021, this contractually-defined percentage was ~~59.8%~~59.5%. Non-performance under these covenants could result in an event of default under these credit agreements. In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements. This condition also applies in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable. However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

The revolving credit ~~facility does~~facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders and AEP manages its borrowings to stay within those authorized limits.

At-the-Market (ATM) Program

AEP participates in an ATM offering program that allows AEP to issue, from time to time, up to an aggregate of $1 billion of its common stock, including shares of common stock that may be sold pursuant to an equity forward sales agreement. As of March 31, 2021, approximately $840 million of equity is available for issuance under the ATM offering program. See Note 12 - Financing Activities for additional information.

Equity Units

In August 2020, AEP issued 17 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $850 million. Net proceeds from the issuance were approximately $833 million. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 1.30% Junior Subordinated Notes due in 2025 and a forward equity purchase contract which settles after three years in 2023. The proceeds were used to support AEP’s overall capital expenditure plans.

In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes due in 2024 and a forward equity purchase contract which settles after three years in 2022. The proceeds from this issuance were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC.

See Note 12 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of ~~$0.70~~$0.74 per share in April ~~2020.~~2021. Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 12 for additional information.

Credit Ratings

AEP and its utility subsidiaries do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but its access to the commercial paper market may depend on its credit ratings. In addition, downgrades in AEP’s credit ratings by one of the rating agencies could increase its borrowing costs. Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject AEP to additional collateral demands under adequate assurance clauses under its derivative and non-derivative energy contracts.

CASH FLOW

AEP relies primarily on cash flows from operations, debt issuances and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.


	Three Months Ended March 31,
	2021		2020
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	438.3	$	432.6
Net Cash Flows from (Used for) Operating Activities	(117.2)		615.7
Net Cash Flows Used for Investing Activities	(1,634.2)		(1,766.0)
Net Cash Flows from Financing Activities	1,637.1		2,388.5

Net Increase (Decrease) in Cash and Cash Equivalents	(114.3)		1,238.2
Cash, Cash Equivalents and Restricted Cash at End of Period	$	324.0	$	1,670.8

Three Months Ended
March 31,
2020 2019
(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period $ 432.6
$ 444.1
Net Cash Flows from Operating Activities 615.7
808.3
Net Cash Flows Used for Investing Activities (1,766.0 ) (1,582.8 )
Net Cash Flows from Financing Activities 2,388.5
693.5
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 1,238.2
(81.0 )
Cash, Cash Equivalents and Restricted Cash at End of Period $ 1,670.8
$ 363.1

Operating Activities


	Three Months Ended March 31,
	2021		2020
	(in millions)
Net Income	$	578.8	$	499.3
Non-Cash Adjustments to Net Income (a)	762.7		726.2
Mark-to-Market of Risk Management Contracts	21.0		57.4

Property Taxes	(74.8)		(59.8)
Deferred Fuel Over/Under-Recovery, Net	(1,225.1)		63.1


Change in Other Noncurrent Assets	(168.9)		(84.9)
Change in Other Noncurrent Liabilities	83.5		(74.8)
Change in Certain Components of Working Capital	(94.4)		(510.8)
Net Cash Flows from (Used for) Operating Activities	$	(117.2)	$	615.7

Three Months Ended
March 31,
2020 2019
(in millions)
Net Income $ 499.3
$ 574.1
Non-Cash Adjustments to Net Income (a) 692.1
618.8
Mark-to-Market of Risk Management Contracts 57.4
65.5
Property Taxes (59.8 ) (75.6 )
Deferred Fuel Over/Under-Recovery, Net 63.1
32.5
Recovery of Ohio Capacity Costs —
14.7
Refund of Global Settlement —
(4.1 )
Change in Other Noncurrent Assets (50.8 ) (47.9 )
Change in Other Noncurrent Liabilities (74.8 ) 67.3
Change in Certain Components of Working Capital (510.8 ) (437.0 )
Net Cash Flows from Operating Activities $ 615.7
$ 808.3

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Rockport Plant, Unit 2 Operating Lease Amortization, Deferred Income Taxes, AFUDC and Amortization of Nuclear Fuel.


~~(a)~~	~~Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, AFUDC and Amortization of Nuclear Fuel.~~

Net Cash Flows from (Used for) Operating Activities decreased by ~~$193~~$733 million primarily due to the following:

•A ~~$142~~$1.3 billion decrease in cash primarily due to fuel and purchased power expenses incurred as a result of the February 2021 severe winter weather event in SPP impacting PSO and SWEPCo. Approximately $1.2 billion of these expenses are attributable to retail customers and are recorded as deferred fuel regulatory assets. PSO and SWEPCo are working with their respective regulatory commissions to determine the recovery period from customers as well as the appropriate carrying charge on the regulatory assets. See Note 4 - Rate Matters for additional information.

•A $131 million decrease in cash ~~from Change in Other Noncurrent Liabilities primarily~~ due to ~~increases~~incremental other operation and maintenance storm restoration expenses incurred by APCo, SWEPCo and KPCo as a result of the February 2021 severe winter weather event. These incremental expenses have been deferred as regulatory assets. APCo and KPCo intend to seek recovery of these costs in ~~revenue refunds related~~their next respective base rate cases while SWEPCo is expected to ~~Tax Reform and Ohio regulatory liabilities.~~seek recovery in a separate filing. See Note 4 - Rate Matters for additional information.

These decreases in cash were partially offset by:

•A ~~$74~~$416 million ~~decrease~~increase in cash from the Change in Certain Components of Working Capital. The ~~decrease~~increase is primarily due to timing of accounts ~~receivable and accounts~~ payable ~~an increase in employee-related payments, a decrease in current year employee-related expenses~~ and a decrease in ~~accrued taxes primarily due to the Alternative Minimum Tax Credit Refund recorded~~fuel, material and supplies balances as a result of the ~~Coronavirus Aid, Relief,~~cold winter weather.

•A $158million increase in cash from Change in Other Noncurrent Liabilities. Increase is primarily due to changes in regulatory liabilities driven by timing differences between collections from and ~~Economic Security Act. These decreases were partially offset by a refund from the Department of Energy for SNF and by the reversal of a regulatory provision at OPCo in the prior year.~~refunds to customers under rate rider mechanisms.

Investing Activities


	Three Months Ended March 31,
	2021		2020
	(in millions)
Construction Expenditures	$	(1,492.7)	$	(1,792.7)
Acquisitions of Nuclear Fuel	(55.9)		(1.3)


Acquisition of the Dry Lake Solar Project	(102.9)		—
Other	17.3		28.0
Net Cash Flows Used for Investing Activities	$	(1,634.2)	$	(1,766.0)

Three Months Ended
March 31,
2020 2019
(in millions)
Construction Expenditures $ (1,792.7 ) $ (1,565.4 )
Acquisitions of Nuclear Fuel (1.3 ) (32.4 )
Other 28.0
15.0
Net Cash Flows Used for Investing Activities $ (1,766.0 ) $ (1,582.8 )

Net Cash Flows Used for Investing Activities ~~increased~~decreased by ~~$183~~$132 million primarily due to the following:

•A ~~$227~~$300 million ~~increase due to increased~~decrease in construction expenditures, primarily ~~driven by increases~~due to decreases at ~~AEP Transmission Holdco of $120 million,~~ Vertically Integrated Utilities of ~~$84~~$125 million, ~~and~~ Transmission and Distribution Utilities of ~~$19~~$87 million and AEP Transmission Holdco of $74 million.

This decrease in the use of cash was partially offset by:

•A $103 million increase due to the acquisition of the Dry Lake Solar Project. See Note 6 - Acquisitions for additional information.

•A $55 million increase in the acquisition of nuclear fuel.

Financing Activities


	Three Months Ended March 31,
	2021		2020
	(in millions)
Issuance of Common Stock	$	184.6	$	56.1
Issuance/Retirement of Debt, Net	1,869.9		2,744.2

Dividends Paid on Common Stock	(372.0)		(363.7)
Other	(45.4)		(48.1)
Net Cash Flows from Financing Activities	$	1,637.1	$	2,388.5

Three Months Ended
March 31,
2020 2019
(in millions)
Issuance of Common Stock $ 56.1
$ 14.5
Issuance/Retirement of Debt, Net 2,744.2
1,013.0
Dividends Paid on Common Stock (363.7 ) (333.6 )
Other (48.1 ) (0.4 )
Net Cash Flows from Financing Activities $ 2,388.5
$ 693.5

Net Cash Flows from Financing Activities ~~increased~~decreased by ~~$1.7 billion~~$751 million primarily due to the following:

•A ~~$1.7~~$1.1 billion ~~increase~~decrease in ~~cash~~short-term debt primarily due to ~~an increase in short-term debt including the 364-day Term Loan borrowing.~~decreased draws on commercial paper. See Note 12 - Financing Activities for additional information.

•A ~~$133~~$350 million decrease due to increased retirements of long-term debt. See Note 12 - Financing Activities for additional information.

These decreases in cash were partially offset by:

•A $533 million increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.

~~This~~•A $129 million increase in ~~cash was partially offset by:~~

~~An $80 million decrease in cash~~issuances of common stock primarily due to ~~increased retirements of long-term debt.~~AEP’s participation in an At-the-Market offering program. See Note 12 - Financing Activities for additional information.

See “Long-term Debt Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after March 31, ~~2020~~2021 through ~~May 6, 2020,~~April 22, 2021, the date that the first quarter 10-Q was issued.

BUDGETED CAPITAL EXPENDITURES

Management ~~currently estimates $5.8~~forecasts approximately $7.5 billion of capital expenditures ~~for 2020 and~~in 2021. For the four year period, 2022 through 2025, management forecasts ~~approximately $32.9 billion of~~ capital expenditures ~~for 2020 to 2024. Capital expenditures related to North Central Wind Energy Facilities are excluded from these budgeted amounts.~~of $29.8 billion. The expenditures are generally for transmission, generation, distribution, regulated and contracted renewables, and required environmental investment to comply with the Federal EPA rules. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital. Management expects to fund these capital expenditures through cash flows from operations and financing activities. Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. For complete information of forecasted capital expenditures, see the “Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the ~~2019~~2020 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the ~~2019~~2020 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the ~~2019~~2020 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting standards.

ACCOUNTING STANDARDS

See Note 2 - New Accounting Standards for information related to accounting standards. There are no new standards ~~adopted in 2020 and standards effective in~~expected to have a material impact to the ~~future.~~Registrants’ financial statements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

The Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through transactions in power, coal, natural gas and marketing contracts. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates.

The Transmission and Distribution Utilities segment is exposed to energy procurement risk and interest rate risk.

The Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. This segment is exposed to certain market risks as a marketer of wholesale and retail electricity. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates. In addition, the Generation & Marketing segment is also exposed to certain market risks as a power producer and through transactions in wholesale electricity, natural gas and marketing contracts.

Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts. Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. As a result, AEP is subject to price risk. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, Executive Vice President of Generation, Executive Vice President of Utilities, Senior Vice President of ~~Commercial Operations,~~Grid Solutions, Senior Vice President of Treasury and Risk and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Financial Officer, Senior Vice President of Treasury and Risk and Chief Risk Officer in addition to Energy Supply’s President and Vice President. When commercial activities exceed predetermined limits, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.

The effects of COVID-19 may adversely impact AEP’s risk management contracts on a forward basis. Markets could experience reduced market liquidity as they face potential uncertainties. Credit risk may increase as counterparties encounter business and supply chain disruptions and overall solvency challenges. Also, interest rates could continue to see increased volatility as capital markets confront uncertainty.

Due to multiple defaults of market participants, ERCOT has a large outstanding unpaid balance associated with the February storm. Socialized losses are allocated to load serving entities through their qualified scheduling entities and in that role AEPEP is exposed, but not materially. If the market rules were to change on how socialized losses are allocated this could affect AEPEP’s exposure. Regardless of the approach of how socialized losses are allocated there are potential downstream impacts that could push counterparties into financial distress and or bankruptcy, affecting AEPEP, AEP Texas and ETT.

The following table summarizes the reasons for changes in total MTM value as compared to December 31, ~~2019:~~2020:


MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 2021

	Vertically Integrated Utilities		Transmission and Distribution Utilities		Generation & Marketing		Total
	(in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2020	$	41.2	$	(109.5)	$	168.1	$	99.8
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period	(21.6)		(2.6)		(7.5)		(31.7)


Changes in Fair Value Due to Market Fluctuations During the Period (a)	—		—		3.4		3.4
Changes in Fair Value Allocated to Regulated Jurisdictions (b)	(3.4)		9.5		—		6.1
Total MTM Risk Management Contract Net Assets (Liabilities) as of March 31, 2021	$	16.2	$	(102.6)	$	164.0	77.6
Commodity Cash Flow Hedge Contracts							(22.8)

Fair Value Hedge Contracts							(34.7)
Collateral Deposits							4.7

Total MTM Derivative Contract Net Assets as of March 31, 2021							$	24.8

MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 2020

Vertically
Integrated
Utilities

Transmission
and
Distribution
Utilities

Generation
&
Marketing
Total
(in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2019 $ 75.9
$ (103.6 ) $ 163.4
$ 135.7
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period (36.7 ) (2.1 ) (6.9 ) (45.7 )
Fair Value of New Contracts at Inception When Entered During the Period (a) —
—
0.5
0.5
Changes in Fair Value Due to Market Fluctuations During the Period (b) —
—
(7.4 ) (7.4 )
Changes in Fair Value Allocated to Regulated Jurisdictions (c) (29.1 ) (17.3 ) —
(46.4 )
Total MTM Risk Management Contract Net Assets (Liabilities) as of March 31, 2020 $ 10.1
$ (123.0 ) $ 149.6
36.7
Commodity Cash Flow Hedge Contracts

(159.1 )
Interest Rate Cash Flow Hedge Contracts

(5.0 )
Fair Value Hedge Contracts

57.0
Collateral Deposits

75.8
Total MTM Derivative Contract Net Assets as of March 31, 2020

$ 5.4

(a)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.

(b)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable.


~~(a)~~	Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.


~~(b)~~	~~Market fluctuations are attributable to various factors such as supply/demand, weather, etc.~~


~~(c)~~	~~Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable.~~

See Note 9 – Derivatives and Hedging and Note 10 – Fair Value Measurements for additional information related to risk management contracts. The following tables and discussion provide information on credit risk and market volatility risk.

Credit Risk

Credit risk is mitigated in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

AEP has risk management contracts (includes non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of March 31, ~~2020,~~2021, credit exposure net of collateral to sub investment grade counterparties was approximately ~~6.9%~~4.1%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).

As of March 31, ~~2020,~~2021, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:


Counterparty Credit Quality	Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties >10% of Net Exposure	Net Exposure of Counterparties >10%
	(in millions, except number of counterparties)
Investment Grade	$	373.8	$	—	$	373.8	2	$	190.0
Split Rating	2.2		—		2.2		2	2.2
Noninvestment Grade	0.4		—		0.4		1	0.4
No External Ratings:
Internal Investment Grade	151.0		—		151.0		3	100.3
Internal Noninvestment Grade	22.7		0.5		22.2		2	13.1
Total as of March 31, 2021	$	550.1	$	0.5	$	549.6

Counterparty Credit Quality
Exposure
Before
Credit
Collateral

Credit
Collateral

Net
Exposure
Number of
Counterparties
>10% of
Net Exposure
Net Exposure
of
Counterparties
>10%
(in millions, except number of counterparties)
Investment Grade $ 493.5
$ —
$ 493.5
2
$ 255.5
Split Rating 3.0
—
3.0
2
3.0
No External Ratings:

Internal Investment Grade 148.8
—
148.8
3
90.7
Internal Noninvestment Grade 58.5
10.5
48.0
2
30.1
Total as of March 31, 2020 $ 703.8
$ 10.5
$ 693.3

All exposure in the table above relates to AEPSC and AEPEP as AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries and AEPEP is agent for and transacts on behalf of other AEP subsidiaries.

In addition, AEP is exposed to credit risk related to participation in RTOs. For each of the RTOs in which AEP participates, this risk is generally determined based on the proportionate share of member gross activity over a specified period of time.

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of March 31, ~~2020,~~2021, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

Management calculates the VaR for both a trading and non-trading portfolio. The trading portfolio consists primarily of contracts related to energy trading and marketing activities. The non-trading portfolio consists primarily of economic hedges of generation and retail supply activities.

The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:

VaR Model

Trading Portfolio

Three Months Ended Twelve Months Ended
March 31, 2020 December 31, 2019
End High Average Low End High Average Low
(in millions) (in millions)
$ 0.1
$ 0.3
$ 0.1
$ —
$ 0.1
$ 1.2
$ 0.2
$ 0.1


Three Months Ended								Twelve Months Ended
March 31, 2021								December 31, 2020
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	0.1	$	3.6	$	0.2	$	0.1	$	0.1	$	0.3	$	0.1	$	—

VaR Model

Non-Trading Portfolio


Three Months Ended								Twelve Months Ended
March 31, 2021								December 31, 2020
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	1.0	$	3.7	$	1.9	$	1.0	$	2.2	$	2.9	$	1.0	$	0.1

Three Months Ended Twelve Months Ended
March 31, 2020 December 31, 2019
End High Average Low End High Average Low
(in millions) (in millions)
$ 0.7
$ 1.2
$ 0.6
$ 0.1
$ 0.2
$ 8.5
$ 1.1
$ 0.2

Management back-tests VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

As the VaR calculation captures recent price movements, management also performs regular stress testing of the trading portfolio to understand AEP’s exposure to extreme price movements. A historical-based method is employed whereby the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss. Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee, Regulated Risk Committee or Competitive Risk Committee as appropriate.

Interest Rate Risk

AEP is exposed to interest rate market fluctuations in the normal course of business operations. AEP has outstanding short and long-term debt which is subject to a variable rate. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. For the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by ~~$24~~$40 million and ~~$25~~$24 million, respectively.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions, except per-share and share amounts)

(Unaudited)



	Three Months Ended March 31,
	2021		2020
REVENUES
Vertically Integrated Utilities	$	2,504.5	$	2,193.0
Transmission and Distribution Utilities	1,082.3		1,075.2
Generation & Marketing	601.7		408.4
Other Revenues	92.6		70.9
TOTAL REVENUES	4,281.1		3,747.5

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	1,560.7		1,151.0

Other Operation	592.4		602.1
Maintenance	274.9		249.5


Depreciation and Amortization	696.3		672.2
Taxes Other Than Income Taxes	346.5		321.1
TOTAL EXPENSES	3,470.8		2,995.9

OPERATING INCOME	810.3		751.6

Other Income (Expense):


Other Income (Expense)	21.7		(4.4)
Allowance for Equity Funds Used During Construction	33.4		31.4
Non-Service Cost Components of Net Periodic Benefit Cost	29.6		29.7

Interest Expense	(290.2)		(292.1)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	604.8		516.2

Income Tax Expense	54.5		46.5
Equity Earnings of Unconsolidated Subsidiaries	28.5		29.6





NET INCOME	578.8		499.3

Net Income Attributable to Noncontrolling Interests	3.8		4.1

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	575.0	$	495.2

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	497,058,635		494,596,869



TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.16	$	1.00

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	498,164,219		496,608,918



TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.15	$	1.00



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Three Months Ended March 31,
2020 2019
REVENUES
Vertically Integrated Utilities $ 2,193.0
$ 2,372.3
Transmission and Distribution Utilities 1,075.2
1,179.8
Generation & Marketing 408.4
439.7
Other Revenues 70.9
65.0
TOTAL REVENUES 3,747.5
4,056.8

EXPENSES

Fuel and Other Consumables Used for Electric Generation 355.3
550.4
Purchased Electricity for Resale 795.7
861.8
Other Operation 602.1
666.0
Maintenance 249.5
274.5
Depreciation and Amortization 672.2
605.8
Taxes Other Than Income Taxes 321.1
309.9
TOTAL EXPENSES 2,995.9
3,268.4

OPERATING INCOME 751.6
788.4

Other Income (Expense):

Other Income (Expense) (4.4 ) 8.6
Allowance for Equity Funds Used During Construction 31.4
28.9
Non-Service Cost Components of Net Periodic Benefit Cost 29.7
30.0
Interest Expense (292.1 ) (255.8 )

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 516.2
600.1

Income Tax Expense 46.5
44.5
Equity Earnings of Unconsolidated Subsidiaries 29.6
18.5

NET INCOME 499.3
574.1

Net Income Attributable to Noncontrolling Interests 4.1
1.3

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 495.2
$ 572.8

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING 494,596,869
493,309,076

TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 1.00
$ 1.16

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 496,608,918
494,484,144

TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 1.00
$ 1.16



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2021		2020
Net Income	$	578.8	$	499.3

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $15.0 and $(17.8) in 2021 and 2020, Respectively	56.3		(67.0)

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.5) and $(0.5) in 2021 and 2020, Respectively	(2.0)		(1.8)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	54.3		(68.8)

TOTAL COMPREHENSIVE INCOME	633.1		430.5

Total Other Comprehensive Income Attributable To Noncontrolling Interests	3.8		4.1

TOTAL OTHER COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	629.3	$	426.4

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Three Months Ended March 31,
2020 2019
Net Income $ 499.3
$ 574.1

OTHER COMPREHENSIVE LOSS, NET OF TAXES

Cash Flow Hedges, Net of Tax of $(17.8) and $(7.7) in 2020 and 2019, Respectively (67.0 ) (28.9 )
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.5) and $(0.4) in 2020 and 2019, Respectively (1.8 ) (1.4 )

TOTAL OTHER COMPREHENSIVE LOSS (68.8 ) (30.3 )

TOTAL COMPREHENSIVE INCOME 430.5
543.8

Total Other Comprehensive Income Attributable To Noncontrolling Interests 4.1
1.3

TOTAL OTHER COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 426.4
$ 542.5



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	AEP Common Shareholders
	Common Stock								Accumulated Other Comprehensive Income (Loss)
	Shares	Amount		Paid-in Capital		Retained Earnings					Noncontrolling Interests		Total
TOTAL EQUITY – DECEMBER 31, 2019	514.4	$	3,343.4	$	6,535.6	$	9,900.9		$	(147.7)	$	281.0	$	19,913.2

Issuance of Common Stock	1.0	6.8		49.3									56.1
Common Stock Dividends						(359.1)		(a)			(4.6)		(363.7)
Other Changes in Equity				(29.0)							(1.2)		(30.2)

ASU 2016-13 Adoption						1.8							1.8
Net Income						495.2					4.1		499.3
Other Comprehensive Loss									(68.8)				(68.8)
TOTAL EQUITY – MARCH 31, 2020	515.4	$	3,350.2	$	6,555.9	$	10,038.8		$	(216.5)	$	279.3	$	20,007.7

















TOTAL EQUITY – DECEMBER 31, 2020	516.8	$	3,359.3	$	6,588.9	$	10,687.8		$	(85.1)	$	223.6	$	20,774.5

Issuance of Common Stock	2.7	17.1		167.5									184.6
Common Stock Dividends						(369.5)		(a)			(2.5)		(372.0)
Other Changes in Equity				(21.9)		(0.6)					3.4		(19.1)
Acquisition of Dry Lake Solar Project											18.9		18.9
Net Income						575.0					3.8		578.8
Other Comprehensive Income									54.3				54.3
TOTAL EQUITY – MARCH 31, 2021	519.5	$	3,376.4	$	6,734.5	$	10,892.7		$	(30.8)	$	247.2	$	21,220.0

AEP Common Shareholders
Common Stock Accumulated
Other
Comprehensive
Income (Loss)
Shares Amount Paid-in
Capital Retained
Earnings Noncontrolling
Interests Total
TOTAL EQUITY – DECEMBER 31, 2018 513.5
$ 3,337.4
$ 6,486.1
$ 9,325.3
$ (120.4 ) $ 31.0
$ 19,059.4

Issuance of Common Stock 0.1
1.2
13.3

14.5
Common Stock Dividends (332.5 ) (b) (1.1 ) (333.6 )
Other Changes in Equity (56.6 ) (a) 1.0
(55.6 )
Net Income 572.8
1.3
574.1
Other Comprehensive Loss

(30.3 ) (30.3 )
TOTAL EQUITY – MARCH 31, 2019 513.6
$ 3,338.6
$ 6,442.8
$ 9,565.6
$ (150.7 ) $ 32.2
$ 19,228.5

TOTAL EQUITY – DECEMBER 31, 2019 514.4
$ 3,343.4
$ 6,535.6
$ 9,900.9
$ (147.7 ) $ 281.0
$ 19,913.2

Issuance of Common Stock 1.0
6.8
49.3
56.1
Common Stock Dividends (359.1 ) (b) (4.6 ) (363.7 )
Other Changes in Equity (29.0 ) (1.2 ) (30.2 )
ASU 2016-13 Adoption 1.8
1.8
Net Income 495.2
4.1
499.3
Other Comprehensive Loss (68.8 ) (68.8 )
TOTAL EQUITY – MARCH 31, 2020 515.4
$ 3,350.2
$ 6,555.9
$ 10,038.8
$ (216.5 ) $ 279.3
$ 20,007.7

(a) Cash dividends declared per AEP common share were $0.74 and $0.70 for the three months ended March 31, 2021 and 2020.


~~(a)~~	~~Includes $(62) million related to a forward equity purchase contract associated with the issuance of Equity Units.~~


~~(b)~~	~~Cash dividends declared per AEP common share were $0.70 and $0.67 for the three months ended March 31, 2020 and 2019, respectively.~~

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page ~~110~~114.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, ~~2020~~2021 and December 31, ~~2019~~2020

(in millions)

(Unaudited)


	March 31,		December 31,
	2021		2020
CURRENT ASSETS
Cash and Cash Equivalents	$	273.2	$	392.7
Restricted Cash (March 31, 2021 and December 31, 2020 Amounts Include $50.8 and $45.6, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding)	50.8		45.6
Other Temporary Investments (March 31, 2021 and December 31, 2020 Amounts Include $191.7 and $194.6, Respectively, Related to EIS and Transource Energy)	199.1		200.8
Accounts Receivable:
Customers	763.0		613.6
Accrued Unbilled Revenues	199.9		248.7
Pledged Accounts Receivable – AEP Credit	919.0		1,018.4
Miscellaneous	36.1		33.1
Allowance for Uncollectible Accounts	(59.6)		(71.1)
Total Accounts Receivable	1,858.4		1,842.7
Fuel	588.6		629.4
Materials and Supplies	683.3		680.6
Risk Management Assets	72.1		94.7
Accrued Tax Benefits	187.6		185.3
Regulatory Asset for Under-Recovered Fuel Costs	129.8		90.7
Margin Deposits	91.0		62.0

Prepayments and Other Current Assets	124.5		127.0
TOTAL CURRENT ASSETS	4,258.4		4,351.5

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	23,186.5		23,133.9
Transmission	28,359.9		27,886.7
Distribution	24,311.8		23,972.1
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	5,465.2		5,294.6
Construction Work in Progress	4,289.5		4,025.7
Total Property, Plant and Equipment	85,612.9		84,313.0
Accumulated Depreciation and Amortization	20,916.8		20,411.4
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	64,696.1		63,901.6

OTHER NONCURRENT ASSETS
Regulatory Assets	4,885.6		3,527.0
Securitized Assets	632.5		657.0
Spent Nuclear Fuel and Decommissioning Trusts	3,414.3		3,306.7
Goodwill	52.5		52.5
Long-term Risk Management Assets	264.8		242.2
Operating Lease Assets	818.9		866.4
Deferred Charges and Other Noncurrent Assets	3,962.0		3,852.3
TOTAL OTHER NONCURRENT ASSETS	14,030.6		12,504.1

TOTAL ASSETS	$	82,985.1	$	80,757.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

March 31, December 31,
2020 2019
CURRENT ASSETS

Cash and Cash Equivalents $ 1,554.6
$ 246.8
Restricted Cash
(March 31, 2020 and December 31, 2019 Amounts Include $116.2 and $185.8, Respectively, Related to Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Santa Rita East) 116.2
185.8
Other Temporary Investments
(March 31, 2020 and December 31, 2019 Amounts Include $163.6 and $187.8, Respectively, Related to EIS and Transource Energy) 185.2
202.7
Accounts Receivable:

Customers 617.9
625.3
Accrued Unbilled Revenues 242.2
222.4
Pledged Accounts Receivable – AEP Credit 885.2
873.9
Miscellaneous 41.1
27.2
Allowance for Uncollectible Accounts (44.9 ) (43.7 )
Total Accounts Receivable 1,741.5
1,705.1
Fuel 550.9
528.5
Materials and Supplies 645.0
640.7
Risk Management Assets 130.4
172.8
Regulatory Asset for Under-Recovered Fuel Costs 80.8
92.9
Margin Deposits 68.3
60.4
Prepayments and Other Current Assets 219.1
242.1
TOTAL CURRENT ASSETS 5,292.0
4,077.8

PROPERTY, PLANT AND EQUIPMENT

Electric:

Generation 22,853.7
22,762.4
Transmission 25,314.2
24,808.6
Distribution 22,824.4
22,443.4
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 4,913.2
4,811.5
Construction Work in Progress 4,511.5
4,319.8
Total Property, Plant and Equipment 80,417.0
79,145.7
Accumulated Depreciation and Amortization 19,368.1
19,007.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 61,048.9
60,138.1

OTHER NONCURRENT ASSETS

Regulatory Assets 3,197.4
3,158.8
Securitized Assets 789.1
858.1
Spent Nuclear Fuel and Decommissioning Trusts 2,679.2
2,975.7
Goodwill 52.5
52.5
Long-term Risk Management Assets 323.7
266.6
Operating Lease Assets 926.7
957.4
Deferred Charges and Other Noncurrent Assets 3,414.5
3,407.3
TOTAL OTHER NONCURRENT ASSETS 11,383.1
11,676.4

TOTAL ASSETS $ 77,724.0
$ 75,892.3



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

March 31, ~~2020~~2021 and December 31, ~~2019~~2020

(in millions, except per-share and share amounts)

(Unaudited)

March 31, December 31,
2020 2019
CURRENT LIABILITIES
Accounts Payable $ 1,593.4
$ 2,085.8
Short-term Debt:
Securitized Debt for Receivables – AEP Credit 724.0
710.0
Other Short-term Debt 3,740.1
2,128.3
Total Short-term Debt 4,464.1
2,838.3
Long-term Debt Due Within One Year
(March 31, 2020 and December 31, 2019 Amounts Include $289.6 and $565.1, Respectively, Related to Transition Funding, DCC Fuel, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding) 2,109.7
1,598.7
Risk Management Liabilities 156.8
114.3
Customer Deposits 361.0
366.1
Accrued Taxes 1,255.4
1,357.8
Accrued Interest 307.9
243.6
Obligations Under Operating Leases 234.3
234.1
Regulatory Liability for Over-Recovered Fuel Costs 137.6
86.6
Other Current Liabilities 1,034.5
1,373.8
TOTAL CURRENT LIABILITIES 11,654.7
10,299.1

NONCURRENT LIABILITIES
Long-term Debt
(March 31, 2020 and December 31, 2019 Amounts Include $1,037.6 and $907, Respectively, Related to Transition Funding, DCC Fuel, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding) 25,783.0
25,126.8
Long-term Risk Management Liabilities 291.9
261.8
Deferred Income Taxes 7,668.5
7,588.2
Regulatory Liabilities and Deferred Investment Tax Credits 8,049.2
8,457.6
Asset Retirement Obligations 2,254.2
2,216.6
Employee Benefits and Pension Obligations 451.0
466.0
Obligations Under Operating Leases 736.3
734.6
Deferred Credits and Other Noncurrent Liabilities 709.5
719.8
TOTAL NONCURRENT LIABILITIES 45,943.6
45,571.4

TOTAL LIABILITIES 57,598.3
55,870.5

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

MEZZANINE EQUITY
Redeemable Noncontrolling Interest 64.8
65.7
Contingently Redeemable Performance Share Awards 53.2
42.9
TOTAL MEZZANINE EQUITY 118.0
108.6

EQUITY
Common Stock – Par Value – $6.50 Per Share:
2020 2019
Shares Authorized 600,000,000 600,000,000
Shares Issued 515,411,847 514,373,631
(20,204,160 Shares were Held in Treasury as of March 31, 2020 and December 31, 2019, Respectively) 3,350.2
3,343.4
Paid-in Capital 6,555.9
6,535.6
Retained Earnings 10,038.8
9,900.9
Accumulated Other Comprehensive Income (Loss) (216.5 ) (147.7 )
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY 19,728.4
19,632.2

Noncontrolling Interests 279.3
281.0

TOTAL EQUITY 20,007.7
19,913.2

TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY $ 77,724.0
$ 75,892.3

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.


			March 31,		December 31,
			2021		2020
CURRENT LIABILITIES
Accounts Payable			$	1,703.9	$	1,709.7
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			669.0		592.0
Other Short-term Debt			2,379.4		1,887.3
Total Short-term Debt			3,048.4		2,479.3
Long-term Debt Due Within One Year (March 31, 2021 and December 31, 2020 Amounts Include $192.3 and $198.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)			2,130.2		2,086.1
Risk Management Liabilities			39.1		78.8
Customer Deposits			331.0		335.6
Accrued Taxes			1,397.9		1,476.4
Accrued Interest			324.2		267.6
Obligations Under Operating Leases			240.6		241.3
Regulatory Liability for Over-Recovered Fuel Costs			39.1		52.6

Other Current Liabilities			965.7		1,199.3
TOTAL CURRENT LIABILITIES			10,220.1		9,926.7

NONCURRENT LIABILITIES
Long-term Debt (March 31, 2021 and December 31, 2020 Amounts Include $921.1 and $950.1, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)			30,214.8		28,986.4
Long-term Risk Management Liabilities			273.0		232.8
Deferred Income Taxes			8,349.9		8,240.9
Regulatory Liabilities and Deferred Investment Tax Credits			8,466.1		8,378.7
Asset Retirement Obligations			2,483.7		2,469.2
Employee Benefits and Pension Obligations			343.4		336.4
Obligations Under Operating Leases			625.1		638.4
Deferred Credits and Other Noncurrent Liabilities			733.7		728.0
TOTAL NONCURRENT LIABILITIES			51,489.7		50,010.8

TOTAL LIABILITIES			61,709.8		59,937.5

Rate Matters (Note 4)			0		0
Commitments and Contingencies (Note 5)			0		0

MEZZANINE EQUITY

Contingently Redeemable Performance Share Awards			55.3		45.2
TOTAL MEZZANINE EQUITY			55.3		45.2

EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2021	2020
Shares Authorized	600,000,000	600,000,000
Shares Issued	519,450,026	516,808,354
(20,204,160 Shares were Held in Treasury as of March 31, 2021 and December 31, 2020, Respectively)			3,376.4		3,359.3
Paid-in Capital			6,734.5		6,588.9
Retained Earnings			10,892.7		10,687.8
Accumulated Other Comprehensive Income (Loss)			(30.8)		(85.1)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			20,972.8		20,550.9

Noncontrolling Interests			247.2		223.6

TOTAL EQUITY			21,220.0		20,774.5

TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY			$	82,985.1	$	80,757.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Three Months Ended March 31,							Three Months Ended March 31,
	2020			2019				2021		2020
OPERATING ACTIVITIES							OPERATING ACTIVITIES
Net Income	$	499.3		$	574.1		Net Income	$	578.8	$	499.3

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:							Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:			��
Depreciation and Amortization	672.2			605.8			Depreciation and Amortization	696.3		672.2
Rockport Plant, Unit 2 Operating Lease Amortization							Rockport Plant, Unit 2 Operating Lease Amortization	32.8		34.1
Deferred Income Taxes	27.9			16.8			Deferred Income Taxes	44.3		27.9

Allowance for Equity Funds Used During Construction	(31.4		)	(28.9		)	Allowance for Equity Funds Used During Construction	(33.4)		(31.4)
Mark-to-Market of Risk Management Contracts	57.4			65.5			Mark-to-Market of Risk Management Contracts	21.0		57.4
Amortization of Nuclear Fuel	23.4			25.1			Amortization of Nuclear Fuel	22.7		23.4

Property Taxes	(59.8		)	(75.6		)	Property Taxes	(74.8)		(59.8)
Deferred Fuel Over/Under-Recovery, Net	63.1			32.5			Deferred Fuel Over/Under-Recovery, Net	(1,225.1)		63.1
Recovery of Ohio Capacity Costs	—			14.7
Refund of Global Settlement	—			(4.1		)

Change in Other Noncurrent Assets	(50.8		)	(47.9		)	Change in Other Noncurrent Assets	(168.9)		(84.9)
Change in Other Noncurrent Liabilities	(74.8		)	67.3			Change in Other Noncurrent Liabilities	83.5		(74.8)
Changes in Certain Components of Working Capital:							Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(32.6		)	57.5			Accounts Receivable, Net	(12.9)		(32.6)
Fuel, Materials and Supplies	(35.8		)	(26.4		)	Fuel, Materials and Supplies	39.5		(35.8)
Accounts Payable	(111.1		)	(152.6		)	Accounts Payable	171.8		(111.1)
Accrued Taxes, Net	(93.9		)	(77.0		)	Accrued Taxes, Net	(80.8)		(93.9)
Other Current Assets	5.3			(18.8		)	Other Current Assets	(26.3)		5.3
Other Current Liabilities	(242.7		)	(219.7		)	Other Current Liabilities	(185.7)		(242.7)
Net Cash Flows from Operating Activities	615.7			808.3
Net Cash Flows from (Used for) Operating Activities							Net Cash Flows from (Used for) Operating Activities	(117.2)		615.7

INVESTING ACTIVITIES							INVESTING ACTIVITIES
Construction Expenditures	(1,792.7		)	(1,565.4		)	Construction Expenditures	(1,492.7)		(1,792.7)

Purchases of Investment Securities	(632.7		)	(130.4		)	Purchases of Investment Securities	(337.6)		(632.7)
Sales of Investment Securities	635.6			111.9			Sales of Investment Securities	325.5		635.6
Acquisitions of Nuclear Fuel	(1.3		)	(32.4		)	Acquisitions of Nuclear Fuel	(55.9)		(1.3)
Acquisition of the Dry Lake Solar Project							Acquisition of the Dry Lake Solar Project	(102.9)		0

Other Investing Activities	25.1			33.5			Other Investing Activities	29.4		25.1
Net Cash Flows Used for Investing Activities	(1,766.0		)	(1,582.8		)	Net Cash Flows Used for Investing Activities	(1,634.2)		(1,766.0)

FINANCING ACTIVITIES							FINANCING ACTIVITIES
Issuance of Common Stock	56.1			14.5			Issuance of Common Stock	184.6		56.1
Issuance of Long-term Debt	1,418.9			1,285.6			Issuance of Long-term Debt	1,951.5		1,418.9
Issuance of Short-term Debt with Original Maturities greater than 90 Days	1,297.5			—			Issuance of Short-term Debt with Original Maturities greater than 90 Days	644.2		1,297.5
Change in Short-term Debt with Original Maturities less than 90 Days, Net	328.3			(52.0		)	Change in Short-term Debt with Original Maturities less than 90 Days, Net	16.9		328.3
Retirement of Long-term Debt	(300.5		)	(220.6		)	Retirement of Long-term Debt	(650.7)		(300.5)

Redemption of Short-term Debt with Original Maturities Greater than 90 Days							Redemption of Short-term Debt with Original Maturities Greater than 90 Days	(92.0)		0
Principal Payments for Finance Lease Obligations	(15.4		)	(14.3		)	Principal Payments for Finance Lease Obligations	(15.0)		(15.4)
Dividends Paid on Common Stock	(363.7		)	(333.6		)	Dividends Paid on Common Stock	(372.0)		(363.7)

Other Financing Activities	(32.7		)	13.9			Other Financing Activities	(30.4)		(32.7)
Net Cash Flows from Financing Activities	2,388.5			693.5			Net Cash Flows from Financing Activities	1,637.1		2,388.5

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	1,238.2			(81.0		)

Net Increase (Decrease) in Cash and Cash Equivalents							Net Increase (Decrease) in Cash and Cash Equivalents	(114.3)		1,238.2
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	432.6			444.1			Cash, Cash Equivalents and Restricted Cash at Beginning of Period	438.3		432.6
Cash, Cash Equivalents and Restricted Cash at End of Period	$	1,670.8		$	363.1		Cash, Cash Equivalents and Restricted Cash at End of Period	$	324.0	$	1,670.8

SUPPLEMENTARY INFORMATION							SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	212.6		$	168.9		Cash Paid for Interest, Net of Capitalized Amounts	$	220.5	$	212.6
Net Cash Paid (Received) for Income Taxes	(0.6		)	(0.6		)	Net Cash Paid (Received) for Income Taxes	(0.2)		(0.6)
Noncash Acquisitions Under Finance Leases	19.4			23.1			Noncash Acquisitions Under Finance Leases	9.0		19.4
Construction Expenditures Included in Current Liabilities as of March 31,	874.1			846.3			Construction Expenditures Included in Current Liabilities as of March 31,	762.7		874.1
Construction Expenditures Included in Noncurrent Liabilities as of March 31,	8.3			—			Construction Expenditures Included in Noncurrent Liabilities as of March 31,	0		8.3
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,							Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,	6.7		0

Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	1.3			1.0			Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	0.1		1.3
Forward Equity Purchase Contract Included in Current and Noncurrent Liabilities as of March 31,	—			62.1
Noncontrolling Interest Assumed with the Dry Lake Solar Project Acquisition							Noncontrolling Interest Assumed with the Dry Lake Solar Project Acquisition	18.9		0

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.							See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~. 50

AEP TEXAS INC.

AND SUBSIDIARIES

AEP TEXAS INC. AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales



	Three Months Ended March 31,
	2021	2020
	(in millions of KWhs)
Retail:
Residential	2,818	2,466
Commercial	2,074	2,357
Industrial	1,880	2,365
Miscellaneous	137	152
Total Retail	6,909	7,340

Three Months Ended March 31,
2020 2019
(in millions of KWhs)
Retail:

Residential 2,466
2,424
Commercial 2,357
2,091
Industrial 2,365
2,148
Miscellaneous 152
145
Total Retail 7,340
6,808

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2021	2020
	(in degree days)
Actual – Heating (a)	315	91
Normal – Heating (b)	185	185

Actual – Cooling (c)	137	231
Normal – Cooling (b)	126	125

(a)Heating degree days are calculated on a 55 degree temperature base.

(b)Normal Heating/Cooling represents the thirty-year average of degree days.

(c)Cooling degree days are calculated on a 70 degree temperature base.

Three Months Ended March 31,
2020 2019
(in degree days)
Actual – Heating (a) 91
177
Normal – Heating (b) 185
187

Actual – Cooling (c) 231
122
Normal – Cooling (b) 125
123


~~(a)~~	~~Heating degree days are calculated on a 55 degree temperature base.~~


~~(b)~~	~~Normal Heating/Cooling represents the thirty-year average of degree days.~~


~~(c)~~	~~Cooling degree days are calculated on a 70 degree temperature base.~~

First Quarter of ~~2020~~2021 Compared to First Quarter of ~~2019~~2020


AEP Texas Inc. and Subsidiaries
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Net Income
(in millions)

First Quarter of 2020	$	47.6

Changes in Gross Margin:
Retail Margins	(6.3)
Margins from Off-system Sales	(30.2)
Transmission Revenues	15.3
Other Revenues	(38.2)
Total Change in Gross Margin	(59.4)

Changes in Expenses and Other:
Other Operation and Maintenance	(3.2)
Depreciation and Amortization	65.0
Taxes Other Than Income Taxes	(2.3)

Interest Income	(0.4)

Allowance for Equity Funds Used During Construction	(1.0)

Interest Expense	(0.5)
Total Change in Expenses and Other	57.6

Income Tax Expense	0.3

First Quarter of 2021	$	46.1

Reconciliation of First Quarter of 2019 to First Quarter of 2020
Net Income
(in millions)

First Quarter of 2019 $ 34.4

Changes in Gross Margin:
Retail Margins 19.5
Margins from Off-system Sales (0.2 )
Transmission Revenues 11.3
Other Revenues 11.7
Total Change in Gross Margin 42.3

Changes in Expenses and Other:
Other Operation and Maintenance (3.0 )
Depreciation and Amortization (23.6 )
Taxes Other Than Income Taxes 2.5
Interest Income 0.2
Allowance for Equity Funds Used During Construction 3.3
Interest Expense (5.1 )
Total Change in Expenses and Other (25.7 )

Income Tax Expense (3.4 )

First Quarter of 2020 $ 47.6

The major components of the ~~increase~~decrease in Gross Margin ~~defined as revenues less the related direct cost of fuel, including consumption of chemicals~~ were as follows:


•	•Retail Margins decreased $6 million primarily due to the following: • ~~increased $20 million primarily due to the following:~~

A ~~$15~~$25 million ~~increase~~decrease in weather-normalized margins primarily in the residential and commercial ~~and residential~~ classes.

•A $7$15 million ~~increase in revenues primarily~~decrease due to ~~the Transmission Cost Recovery Factor revenue rider.~~refunds of Excess ADIT and excess federal income taxes collected as a result of Tax Reform.

These ~~increases~~decreases were partially offset by:

•A $4$19 million ~~decrease~~increase in weather-related usage primarily due to a ~~49% decrease~~246% increase in heating degree days, partially offset by ~~an 89% increase~~a 41% decrease in cooling degree days.

•

•A $10 million increase from interim rate increases driven by increased distribution investment.

•A $6 million increase from interim rate increases driven by increased transmission investment.

•Margins from Off-system Sales decreased $30 million due to lower Oklaunion Power Station PPA revenues. Oklaunion Power Station was retired in September 2020 and sold to a nonaffiliated third-party in October 2020. This decrease was partially offset in Depreciation and Amortization expenses below.

•Transmission Revenues increased $15 million primarily due to:

•A $19 million increase from interim rate increases driven by increased transmission investment.

This increase was partially offset by:

•A $4 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.

•Other Revenues decreased $38 million primarily due to the following:

•A $46 million decrease in securitization revenues primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.

This decrease was partially offset by:

•An $8 million increase in revenues due to the amortization of a provision for refund recorded as part of the most recent base rate case. This increase was partially offset in Retail Margins and Transmission Revenues above.

~~increased $11 million primarily due to the recovery of increased transmission investment in ERCOT.~~


•	~~Other Revenues~~ ~~increased $12 million primarily due to securitization revenue. This increase was offset below in Depreciation and Amortization expenses and in Interest Expense.~~

Expenses and Other ~~and Income Tax Expense~~ changed between years as follows:


•	•Other Operation and Maintenance expenses increased $3 million primarily due to the following: • ~~expenses increased $3 million primarily due to an increase in distribution-related expenses.~~


•	~~Depreciation and Amortization~~ ~~expenses increased $24 million primarily due to the following:~~

A ~~$12~~$5 million increase in ~~securitization amortizations.~~ transmission expenses, partially offset in Gross Margin above.

This increase was partially offset by:

•A $2 million decrease primarily related to distribution-related expenses.

•Depreciation and Amortization expenses decreased $65 million primarily due to the following:

•A $44 million decrease in securitization amortizations primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. The securitization decrease was offset in Other Revenues ~~above and in Interest Expense below.~~above.

~~An $11~~•A $16 million ~~increase~~decrease in depreciation expense due to ~~an increase~~the retirement of the Oklaunion Power Station in ~~the depreciable base of transmission~~September 2020. This decrease was partially offset above in Margins from Off-system Sales and ~~distribution assets.~~Other Operation and Maintenance expenses.


•	~~Allowance for Equity Funds Used During Construction~~ ~~increased $3 million due to an increase in the Equity component of AFUDC as a result of lower short-term balances and increased transmission projects.~~


•	~~Interest Expense~~ ~~increased~~ ~~$5 million primarily due to higher long-term debt balances.~~


•	~~Income Tax Expense~~ ~~increased $3 million primarily due to an increase in pretax book income.~~

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2021		2020
REVENUES
Electric Transmission and Distribution	$	361.7	$	391.6
Sales to AEP Affiliates	1.0		31.1
Other Revenues	1.5		0.9
TOTAL REVENUES	364.2		423.6

EXPENSES

Other Operation	122.2		117.5
Maintenance	19.1		20.6
Depreciation and Amortization	97.5		162.5
Taxes Other Than Income Taxes	36.3		34.0
TOTAL EXPENSES	275.1		334.6

OPERATING INCOME	89.1		89.0

Other Income (Expense):
Interest Income	0.2		0.6

Allowance for Equity Funds Used During Construction	4.1		5.1

Non-Service Cost Components of Net Periodic Benefit Cost	2.8		2.8
Interest Expense	(43.0)		(42.5)

INCOME BEFORE INCOME TAX EXPENSE	53.2		55.0

Income Tax Expense	7.1		7.4

NET INCOME	$	46.1	$	47.6

The common stock of AEP Texas is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Three Months Ended March 31,
2020 2019
REVENUES
Electric Transmission and Distribution $ 391.6
$ 349.8
Sales to AEP Affiliates 31.1
40.2
Other Revenues 0.9
0.7
TOTAL REVENUES 423.6
390.7

EXPENSES

Fuel and Other Consumables Used for Electric Generation —
9.4
Other Operation 117.5
109.8
Maintenance 20.6
25.3
Depreciation and Amortization 162.5
138.9
Taxes Other Than Income Taxes 34.0
36.5
TOTAL EXPENSES 334.6
319.9

OPERATING INCOME 89.0
70.8

Other Income (Expense):

Interest Income 0.6
0.4
Allowance for Equity Funds Used During Construction 5.1
1.8
Non-Service Cost Components of Net Periodic Benefit Cost 2.8
2.8
Interest Expense (42.5 ) (37.4 )

INCOME BEFORE INCOME TAX EXPENSE 55.0
38.4

Income Tax Expense 7.4
4.0

NET INCOME $ 47.6
$ 34.4

~~The common stock of AEP Texas is wholly-owned by Parent.~~

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2021		2020
Net Income	$	46.1	$	47.6

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2021 and 2020, Respectively	0.3		0.3




TOTAL COMPREHENSIVE INCOME	$	46.4	$	47.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Three Months Ended March 31,
2020 2019
Net Income $ 47.6
$ 34.4

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2020 and 2019, Respectively 0.3
0.3
TOTAL OTHER COMPREHENSIVE INCOME 0.3
0.3

TOTAL COMPREHENSIVE INCOME $ 47.9
$ 34.7

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019	$	1,457.9	$	1,516.0	$	(12.8)	$	2,961.1



Net Income			47.6				47.6
Other Comprehensive Income					0.3		0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020	$	1,457.9	$	1,563.6	$	(12.5)	$	3,009.0











TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020	$	1,457.9	$	1,757.0	$	(8.9)	$	3,206.0


Net Income			46.1				46.1
Other Comprehensive Income					0.3		0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021	$	1,457.9	$	1,803.1	$	(8.6)	$	3,252.4











See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 $ 1,257.9
$ 1,337.7
$ (15.1 ) $ 2,580.5

Capital Contribution from Parent 200.0
200.0
Net Income 34.4
34.4
Other Comprehensive Income 0.3
0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 $ 1,457.9
$ 1,372.1
$ (14.8 ) $ 2,815.2

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019 $ 1,457.9
$ 1,516.0
$ (12.8 ) $ 2,961.1

Net Income 47.6
47.6
Other Comprehensive Income 0.3
0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020 $ 1,457.9
$ 1,563.6
$ (12.5 ) $ 3,009.0

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, ~~2020~~2021 and December 31, ~~2019~~2020

(in millions)

(Unaudited)


	March 31,		December 31,
	2021		2020
CURRENT ASSETS
Cash and Cash Equivalents	$	0.1	$	0.1
Restricted Cash (March 31, 2021 and December 31, 2020 Amounts Include $39.3 and $28.7, Respectively, Related to Transition Funding and Restoration Funding)	39.3		28.7
Advances to Affiliates	6.8		7.1
Accounts Receivable:
Customers	129.3		112.8
Affiliated Companies	7.2		5.1
Accrued Unbilled Revenues	58.2		65.8

Allowance for Uncollectible Accounts	(4.3)		(0.1)
Total Accounts Receivable	190.4		183.6

Materials and Supplies	69.8		70.0

Accrued Tax Benefits	11.4		16.8
Prepayments and Other Current Assets	4.7		4.6
TOTAL CURRENT ASSETS	322.5		310.9

PROPERTY, PLANT AND EQUIPMENT
Electric:

Transmission	5,434.7		5,279.6
Distribution	4,654.2		4,580.8
Other Property, Plant and Equipment	885.0		868.4
Construction Work in Progress	567.8		614.1
Total Property, Plant and Equipment	11,541.7		11,342.9
Accumulated Depreciation and Amortization	1,565.9		1,529.3
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	9,975.8		9,813.6

OTHER NONCURRENT ASSETS
Regulatory Assets	274.5		266.8
Securitized Assets (March 31, 2021 and December 31, 2020 Amounts Include $428.6 and $446.8, Respectively, Related to Transition Funding and Restoration Funding)	428.6		446.8

Deferred Charges and Other Noncurrent Assets	261.6		192.1
TOTAL OTHER NONCURRENT ASSETS	964.7		905.7

TOTAL ASSETS	$	11,263.0	$	11,030.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

March 31, December 31,
2020 2019
CURRENT ASSETS
Cash and Cash Equivalents $ 0.1
$ 3.1
Restricted Cash
(March 31, 2020 and December 31, 2019 Amounts Include $100.1 and $154.7, Respectively, Related to Transition Funding and Restoration Funding) 100.1
154.7
Advances to Affiliates 7.1
207.2
Accounts Receivable:
Customers 130.1
116.0
Affiliated Companies 10.4
10.1
Accrued Unbilled Revenues 88.6
68.8
Miscellaneous 0.4
0.3
Allowance for Uncollectible Accounts (1.8 ) (1.8 )
Total Accounts Receivable 227.7
193.4
Fuel 6.4
5.9
Materials and Supplies 63.8
56.7
Accrued Tax Benefits 51.5
66.1
Prepayments and Other Current Assets 6.6
5.8
TOTAL CURRENT ASSETS 463.3
692.9

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 351.6
351.7
Transmission 4,624.7
4,466.5
Distribution 4,303.1
4,215.2
Other Property, Plant and Equipment 829.1
805.9
Construction Work in Progress 747.0
763.9
Total Property, Plant and Equipment 10,855.5
10,603.2
Accumulated Depreciation and Amortization 1,800.1
1,758.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 9,055.4
8,845.1

OTHER NONCURRENT ASSETS
Regulatory Assets 272.2
280.6
Securitized Assets
(March 31, 2020 and December 31, 2019 Amounts Include $560.7 and $621.2, Respectively, Related to Transition Funding and Restoration Funding) 560.5
623.4
Deferred Charges and Other Noncurrent Assets 219.1
147.1
TOTAL OTHER NONCURRENT ASSETS 1,051.8
1,051.1

TOTAL ASSETS $ 10,570.5
$ 10,589.1

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, ~~2020~~2021 and December 31, ~~2019~~2020

(in millions)

(Unaudited)


	March 31,		December 31,
	2021		2020
CURRENT LIABILITIES
Advances from Affiliates	$	284.0	$	67.1
Accounts Payable:
General	198.8		231.7
Affiliated Companies	24.4		44.0

Long-term Debt Due Within One Year – Nonaffiliated (March 31, 2021 and December 31, 2020 Amounts Include $88.9 and $88.7, Respectively, Related to Transition Funding and Restoration Funding)	88.9		88.7


Accrued Taxes	107.1		78.3
Accrued Interest (March 31, 2021 and December 31, 2020 Amounts Include $3.2 and $2.5, Respectively, Related to Transition Funding and Restoration Funding)	54.7		43.9

Obligations Under Operating Leases	14.5		14.5

Other Current Liabilities	83.4		108.6
TOTAL CURRENT LIABILITIES	855.8		676.8

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (March 31, 2021 and December 31, 2020 Amounts Include $392.7 and $403.9, Respectively, Related to Transition Funding and Restoration Funding)	4,721.3		4,731.7

Deferred Income Taxes	1,024.3		1,016.7
Regulatory Liabilities and Deferred Investment Tax Credits	1,272.0		1,270.8

Obligations Under Operating Leases	68.9		71.0
Deferred Credits and Other Noncurrent Liabilities	68.3		57.2
TOTAL NONCURRENT LIABILITIES	7,154.8		7,147.4

TOTAL LIABILITIES	8,010.6		7,824.2

Rate Matters (Note 4)	0		0
Commitments and Contingencies (Note 5)	0		0

COMMON SHAREHOLDER’S EQUITY
Paid-in Capital	1,457.9		1,457.9
Retained Earnings	1,803.1		1,757.0
Accumulated Other Comprehensive Income (Loss)	(8.6)		(8.9)
TOTAL COMMON SHAREHOLDER’S EQUITY	3,252.4		3,206.0

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	11,263.0	$	11,030.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

March 31, December 31,
2020 2019
CURRENT LIABILITIES
Advances from Affiliates $ 63.9
$ —
Accounts Payable:
General 233.1
256.8
Affiliated Companies 20.3
35.6
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2020 and December 31, 2019 Amounts Include $178.3 and $281.4, Respectively, Related to Transition Funding and Restoration Funding) 289.0
392.1
Accrued Taxes 109.2
84.9
Accrued Interest
(March 31, 2020 and December 31, 2019 Amounts Include $4.9 and $7.5, Respectively, Related to Transition Funding and Restoration Funding) 54.8
35.7
Oklaunion Purchase Power Agreement 15.1
22.1
Obligations Under Operating Leases 13.0
12.0
Provision for Refund 62.9
64.7
Other Current Liabilities 104.3
123.3
TOTAL CURRENT LIABILITIES 965.6
1,027.2

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated
(March 31, 2020 and December 31, 2019 Amounts Include $484.7 and $495.4, Respectively, Related to Transition Funding and Restoration Funding) 4,156.4
4,166.3
Deferred Income Taxes 961.8
965.4
Regulatory Liabilities and Deferred Investment Tax Credits 1,321.8
1,316.9
Obligations Under Operating Leases 70.7
71.1
Deferred Credits and Other Noncurrent Liabilities 85.2
81.1
TOTAL NONCURRENT LIABILITIES 6,595.9
6,600.8

TOTAL LIABILITIES 7,561.5
7,628.0

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Paid-in Capital 1,457.9
1,457.9
Retained Earnings 1,563.6
1,516.0
Accumulated Other Comprehensive Income (Loss) (12.5 ) (12.8 )
TOTAL COMMON SHAREHOLDER’S EQUITY 3,009.0
2,961.1

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 10,570.5
$ 10,589.1

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2021		2020
OPERATING ACTIVITIES
Net Income	$	46.1	$	47.6
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	97.5		162.5
Deferred Income Taxes	1.7		(7.6)
Allowance for Equity Funds Used During Construction	(4.1)		(5.1)


Property Taxes	(71.1)		(69.3)

Change in Other Noncurrent Assets	(14.8)		(10.8)
Change in Other Noncurrent Liabilities	14.7		3.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(6.8)		(34.3)
Fuel, Materials and Supplies	0.3		(7.6)
Accounts Payable	1.4		2.4

Accrued Taxes, Net	34.1		38.9

Other Current Assets	0.3		(1.4)
Other Current Liabilities	(15.2)		(4.6)
Net Cash Flows from Operating Activities	84.1		113.9

INVESTING ACTIVITIES
Construction Expenditures	(295.1)		(327.5)
Change in Advances to Affiliates, Net	0.3		200.1

Other Investing Activities	17.0		7.4
Net Cash Flows Used for Investing Activities	(277.8)		(120.0)

FINANCING ACTIVITIES



Change in Advances from Affiliates, Net	216.9		63.9
Retirement of Long-term Debt – Nonaffiliated	(11.2)		(114.3)
Principal Payments for Finance Lease Obligations	(1.7)		(1.5)

Other Financing Activities	0.3		0.4
Net Cash Flows from (Used for) Financing Activities	204.3		(51.5)

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding	10.6		(57.6)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	28.8		157.8
Cash, Cash Equivalents and Restricted Cash at End of Period	$	39.4	$	100.2

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	30.0	$	21.1

Noncash Acquisitions Under Finance Leases	0.8		3.7
Construction Expenditures Included in Current Liabilities as of March 31,	120.5		175.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Three Months Ended March 31,
2020 2019
OPERATING ACTIVITIES

Net Income $ 47.6
$ 34.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

Depreciation and Amortization 162.5
138.9
Deferred Income Taxes (7.6 ) (11.0 )
Allowance for Equity Funds Used During Construction (5.1 ) (1.8 )
Property Taxes (69.3 ) (73.8 )
Change in Other Noncurrent Assets (10.8 ) (3.2 )
Change in Other Noncurrent Liabilities 3.2
(5.7 )
Changes in Certain Components of Working Capital:

Accounts Receivable, Net (34.3 ) (7.8 )
Fuel, Materials and Supplies (7.6 ) (1.0 )
Accounts Payable 2.4
4.2
Accrued Taxes, Net 38.9
57.5
Other Current Assets (1.4 ) 0.5
Other Current Liabilities (4.6 ) (4.4 )
Net Cash Flows from Operating Activities 113.9
126.8

INVESTING ACTIVITIES

Construction Expenditures (327.5 ) (343.1 )
Change in Advances to Affiliates, Net 200.1
0.3
Other Investing Activities 7.4
6.2
Net Cash Flows Used for Investing Activities (120.0 ) (336.6 )

FINANCING ACTIVITIES

Capital Contribution from Parent —
200.0
Change in Advances from Affiliates, Net 63.9
55.2
Retirement of Long-term Debt – Nonaffiliated (114.3 ) (103.5 )
Principal Payments for Finance Lease Obligations (1.5 ) (1.2 )
Other Financing Activities 0.4
0.2
Net Cash Flows from (Used for) Financing Activities (51.5 ) 150.7

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding (57.6 ) (59.1 )
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at Beginning of Period 157.8
159.8
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at End of Period $ 100.2
$ 100.7

SUPPLEMENTARY INFORMATION

Cash Paid for Interest, Net of Capitalized Amounts $ 21.1
$ 22.4
Net Cash Paid (Received) for Income Taxes —
(5.6 )
Noncash Acquisitions Under Finance Leases 3.7
2.4
Construction Expenditures Included in Current Liabilities as of March 31, 175.1
195.7

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~
~~110~~.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Summary of Investment in Transmission Assets for AEPTCo


	As of March 31,
	2021		2020
	(in millions)
Plant In Service	$	10,144.5	$	8,684.9
Construction Work in Progress	1,549.5		1,536.3
Accumulated Depreciation and Amortization	623.6		445.8
Total Transmission Property, Net	$	11,070.4	$	9,775.4

As of March 31,
2020 2019
(in millions)
Plant In Service $ 8,684.9
$ 6,755.0
Construction Work in Progress 1,536.3
1,812.2
Accumulated Depreciation and Amortization 445.8
306.7
Total Transmission Property, Net $ 9,775.4
$ 8,260.5

First Quarter of ~~2020~~2021 Compared to First Quarter of ~~2019~~2020


AEP Transmission Company, LLC and Subsidiaries
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Net Income
(in millions)

First Quarter of 2020	$	117.8

Changes in Transmission Revenues:
Transmission Revenues	66.1
Total Change in Transmission Revenues	66.1

Changes in Expenses and Other:
Other Operation and Maintenance	2.3
Depreciation and Amortization	(14.6)
Taxes Other Than Income Taxes	(7.4)
Interest Income	(0.7)
Allowance for Equity Funds Used During Construction	0.5
Interest Expense	(4.5)
Total Change in Expenses and Other	(24.4)

Income Tax Expense	(7.8)


First Quarter of 2021	$	151.7

Reconciliation of First Quarter of 2019 to First Quarter of 2020
Net Income
(in millions)

First Quarter of 2019 $ 104.3

Changes in Transmission Revenues:
Transmission Revenues 52.1
Total Change in Transmission Revenues 52.1

Changes in Expenses and Other:
Other Operation and Maintenance (6.8 )
Depreciation and Amortization (15.7 )
Taxes Other Than Income Taxes (9.0 )
Interest Income 0.1
Allowance for Equity Funds Used During Construction 4.9
Interest Expense (7.9 )
Total Change in Expenses and Other (34.4 )

Income Tax Expense (4.2 )

First Quarter of 2020 $ 117.8

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows:


•	•Transmission Revenues increased $66 million primarily due to continued investment in transmission assets. ~~increased $52 million primarily due to continued investment in transmission assets.~~

Expenses and Other and Income Tax Expense changed between years as follows:


•	~~Other Operation and Maintenance~~ •Depreciation and Amortization expenses increased $15 million primarily due to a higher depreciable base. •Taxes Other Than Income Taxes increased $7 million primarily ~~due to the following:~~

~~A $3 million increase due to employee-related expenses.~~

~~A $2 million increase~~ due to higher ~~rent expense.~~property taxes as a result of increased transmission investment.

~~A $1~~•Interest Expense increased $5 million ~~increase~~primarily due to ~~continued investment in transmission assets.~~higher long-term debt balances.


•	~~Depreciation and Amortization~~ ~~expenses increased $16~~ •Income Tax Expense increased $8 million primarily ~~due to a higher depreciable base.~~


•	~~Taxes Other Than Income Taxes~~ ~~increased $9 million primarily due to higher property taxes as a result of increased transmission investment.~~


•	~~Allowance for Equity Funds Used During Construction~~ ~~increased $5 million primarily due to the following:~~

~~A $9 million increase~~ due to ~~prior year FERC audit findings.~~

~~This~~an increase ~~was partially offset by:~~

~~A $5 million decrease due to a decrease~~ in ~~CWIP.~~


•	~~Interest Expense~~ ~~increased $8 million primarily due to higher long-term debt balances.~~


•	~~Income Tax Expense~~ ~~increased $4 million primarily due to higher~~ pretax book income.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)



	Three Months Ended March 31,
		2021		2020
REVENUES
Transmission Revenues		$	76.0	$	61.3
Sales to AEP Affiliates		285.6		233.7
Other Revenues		0.1		0.6
TOTAL REVENUES		361.7		295.6

EXPENSES
Other Operation		21.1		23.8
Maintenance		3.6		3.2
Depreciation and Amortization		70.6		56.0
Taxes Other Than Income Taxes		57.8		50.4
TOTAL EXPENSES		153.1		133.4

OPERATING INCOME		208.6		162.2

Other Income (Expense):
Interest Income - Affiliated		0.1		0.8
Allowance for Equity Funds Used During Construction		16.7		16.2

Interest Expense		(34.1)		(29.6)

INCOME BEFORE INCOME TAX EXPENSE		191.3		149.6

Income Tax Expense		39.6		31.8

NET INCOME		$	151.7	$	117.8

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Three Months Ended March 31,
2020 2019
REVENUES
Transmission Revenues $ 61.3
$ 50.3
Sales to AEP Affiliates 233.7
193.2
Other Revenues 0.6
—
TOTAL REVENUES 295.6
243.5

EXPENSES

Other Operation 23.8
17.0
Maintenance 3.2
3.2
Depreciation and Amortization 56.0
40.3
Taxes Other Than Income Taxes 50.4
41.4
TOTAL EXPENSES 133.4
101.9

OPERATING INCOME 162.2
141.6

Other Income (Expense):

Interest Income - Affiliated 0.8
0.7
Allowance for Equity Funds Used During Construction 16.2
11.3
Interest Expense (29.6 ) (21.7 )

INCOME BEFORE INCOME TAX EXPENSE 149.6
131.9

Income Tax Expense 31.8
27.6

NET INCOME $ 117.8
$ 104.3

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Paid-in Capital		Retained Earnings		Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2019	$	2,480.6	$	1,528.9	$	4,009.5

Capital Contribution from Member	185.0				185.0
Net Income			117.8		117.8
TOTAL MEMBER'S EQUITY – MARCH 31, 2020	$	2,665.6	$	1,646.7	$	4,312.3









TOTAL MEMBER'S EQUITY – DECEMBER 31, 2020	$	2,765.6	$	1,947.3	$	4,712.9

Capital Contribution from Member	124.0				124.0
Net Income			151.7		151.7
TOTAL MEMBER'S EQUITY – MARCH 31, 2021	$	2,889.6	$	2,099.0	$	4,988.6










See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Paid-in
Capital Retained
Earnings Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2018 $ 2,480.6
$ 1,089.2
$ 3,569.8

Net Income
104.3
104.3
TOTAL MEMBER'S EQUITY – MARCH 31, 2019 $ 2,480.6
$ 1,193.5
$ 3,674.1

TOTAL MEMBER'S EQUITY – DECEMBER 31, 2019 $ 2,480.6
$ 1,528.9
$ 4,009.5

Capital Contribution from Member 185.0
185.0
Net Income 117.8
117.8
TOTAL MEMBER'S EQUITY – MARCH 31, 2020 $ 2,665.6
$ 1,646.7
$ 4,312.3

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, ~~2020~~2021 and December 31, ~~2019~~2020

(in millions)

(Unaudited)


	March 31,		December 31,
	2021		2020
CURRENT ASSETS
Advances to Affiliates	$	106.1	$	109.1
Accounts Receivable:
Customers	25.6		22.9
Affiliated Companies	95.0		81.2

Total Accounts Receivable	120.6		104.1
Materials and Supplies	8.8		8.5

Prepayments and Other Current Assets	3.4		14.1
TOTAL CURRENT ASSETS	238.9		235.8

TRANSMISSION PROPERTY
Transmission Property	9,788.3		9,593.5
Other Property, Plant and Equipment	356.2		329.5
Construction Work in Progress	1,549.5		1,422.6
Total Transmission Property	11,694.0		11,345.6
Accumulated Depreciation and Amortization	623.6		572.8
TOTAL TRANSMISSION PROPERTY – NET	11,070.4		10,772.8

OTHER NONCURRENT ASSETS

Regulatory Assets	14.0		15.1
Deferred Property Taxes	190.1		220.1
Deferred Charges and Other Noncurrent Assets	1.7		2.2
TOTAL OTHER NONCURRENT ASSETS	205.8		237.4

TOTAL ASSETS	$	11,515.1	$	11,246.0

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

March 31, December 31,
2020 2019
CURRENT ASSETS
Advances to Affiliates $ 128.4
$ 85.4
Accounts Receivable:
Customers 19.3
19.0
Affiliated Companies 87.8
66.1
Total Accounts Receivable 107.1
85.1
Materials and Supplies 13.4
13.8
Accrued Tax Benefits 0.1
9.3
Prepayments and Other Current Assets 3.4
3.8
TOTAL CURRENT ASSETS 252.4
197.4

TRANSMISSION PROPERTY
Transmission Property 8,406.4
8,137.9
Other Property, Plant and Equipment 278.5
269.6
Construction Work in Progress 1,536.3
1,485.7
Total Transmission Property 10,221.2
9,893.2
Accumulated Depreciation and Amortization 445.8
402.3
TOTAL TRANSMISSION PROPERTY – NET 9,775.4
9,490.9

OTHER NONCURRENT ASSETS
Regulatory Assets 2.5
4.2
Deferred Property Taxes 165.1
193.5
Deferred Charges and Other Noncurrent Assets 4.5
4.8
TOTAL OTHER NONCURRENT ASSETS 172.1
202.5

TOTAL ASSETS $ 10,199.9
$ 9,890.8

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

March 31, ~~2020~~2021 and December 31, ~~2019~~2020

(in millions)

(Unaudited)


	March 31,		December 31,
	2021		2020
CURRENT LIABILITIES
Advances from Affiliates	$	229.3	$	156.7
Accounts Payable:
General	325.3		380.4
Affiliated Companies	72.2		97.3

Long-term Debt Due Within One Year – Nonaffiliated	50.0		50.0
Accrued Taxes	373.2		418.1
Accrued Interest	48.2		23.9
Obligations Under Operating Leases	0.8		1.2
Other Current Liabilities	12.3		9.9
TOTAL CURRENT LIABILITIES	1,111.3		1,137.5

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,899.0		3,898.5
Deferred Income Taxes	917.2		906.9
Regulatory Liabilities	597.1		581.8
Obligations Under Operating Leases	0.4		0.4
Deferred Credits and Other Noncurrent Liabilities	1.5		8.0
TOTAL NONCURRENT LIABILITIES	5,415.2		5,395.6

TOTAL LIABILITIES	6,526.5		6,533.1

Rate Matters (Note 4)	0		0
Commitments and Contingencies (Note 5)	0		0

MEMBER’S EQUITY
Paid-in Capital	2,889.6		2,765.6
Retained Earnings	2,099.0		1,947.3
TOTAL MEMBER’S EQUITY	4,988.6		4,712.9

TOTAL LIABILITIES AND MEMBER’S EQUITY	$	11,515.1	$	11,246.0

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

March 31, December 31,
2020 2019
CURRENT LIABILITIES
Advances from Affiliates $ 297.4
$ 137.0
Accounts Payable:
General 334.2
493.4
Affiliated Companies 73.7
71.2
Accrued Taxes 308.6
355.6
Accrued Interest 38.6
19.2
Obligations Under Operating Leases 2.1
2.1
Other Current Liabilities 17.0
14.6
TOTAL CURRENT LIABILITIES 1,071.6
1,093.1

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated 3,427.8
3,427.3
Deferred Income Taxes 834.7
817.8
Regulatory Liabilities 551.6
540.9
Obligations Under Operating Leases 1.6
1.9
Deferred Credits and Other Noncurrent Liabilities 0.3
0.3
TOTAL NONCURRENT LIABILITIES 4,816.0
4,788.2

TOTAL LIABILITIES 5,887.6
5,881.3

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

MEMBER’S EQUITY
Paid-in Capital 2,665.6
2,480.6
Retained Earnings 1,646.7
1,528.9
TOTAL MEMBER’S EQUITY 4,312.3
4,009.5

TOTAL LIABILITIES AND MEMBER’S EQUITY $ 10,199.9
$ 9,890.8

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2021		2020
OPERATING ACTIVITIES
Net Income	$	151.7	$	117.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	70.6		56.0
Deferred Income Taxes	8.3		13.7
Allowance for Equity Funds Used During Construction	(16.7)		(16.2)
Property Taxes	30.0		28.4

Change in Other Noncurrent Assets	1.4		2.4
Change in Other Noncurrent Liabilities	0.6		0.6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(16.5)		(22.0)
Materials and Supplies	(0.3)		0.4
Accounts Payable	(18.9)		22.7
Accrued Taxes, Net	(35.1)		(37.8)
Accrued Interest	24.3		19.4
Other Current Assets	0.9		0.4
Other Current Liabilities	1.4		1.2
Net Cash Flows from Operating Activities	201.7		187.0

INVESTING ACTIVITIES
Construction Expenditures	(400.5)		(491.5)
Change in Advances to Affiliates, Net	3.0		(43.0)


Other Investing Activities	(0.8)		2.1
Net Cash Flows Used for Investing Activities	(398.3)		(532.4)

FINANCING ACTIVITIES
Capital Contributions from Member	124.0		185.0

Change in Advances from Affiliates, Net	72.6		160.4


Net Cash Flows from Financing Activities	196.6		345.4

Net Change in Cash and Cash Equivalents	0		0
Cash and Cash Equivalents at Beginning of Period	0		0
Cash and Cash Equivalents at End of Period	$	0	$	0

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	8.9	$	9.3
Net Cash Paid for Income Taxes	0		0.1
Construction Expenditures Included in Current Liabilities as of March 31,	244.5		290.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Three Months Ended March 31,
2020 2019
OPERATING ACTIVITIES
Net Income $ 117.8
$ 104.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 56.0
40.3
Deferred Income Taxes 13.7
14.5
Allowance for Equity Funds Used During Construction (16.2 ) (11.3 )
Property Taxes 28.4
23.2
Change in Other Noncurrent Assets 2.4
2.7
Change in Other Noncurrent Liabilities 0.6
2.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (22.0 ) (8.2 )
Materials and Supplies 0.4
(0.6 )
Accounts Payable 22.7
11.4
Accrued Taxes, Net (37.8 ) (32.1 )
Accrued Interest 19.4
19.2
Other Current Assets 0.4
0.4
Other Current Liabilities 1.2
0.2
Net Cash Flows from Operating Activities 187.0
166.2

INVESTING ACTIVITIES

Construction Expenditures (491.5 ) (365.0 )
Change in Advances to Affiliates, Net (43.0 ) 23.4
Acquisitions of Assets (1.7 ) (2.5 )
Other Investing Activities 3.8
0.3
Net Cash Flows Used for Investing Activities (532.4 ) (343.8 )

FINANCING ACTIVITIES
Capital Contributions from Member 185.0
—
Change in Advances from Affiliates, Net 160.4
177.7
Other Financing Activities —
(0.1 )
Net Cash Flows from Financing Activities 345.4
177.6

Net Change in Cash and Cash Equivalents —
—
Cash and Cash Equivalents at Beginning of Period —
—
Cash and Cash Equivalents at End of Period $ —
$ —

SUPPLEMENTARY INFORMATION

Cash Paid for Interest, Net of Capitalized Amounts $ 9.3
$ 1.6
Net Cash Paid (Received) for Income Taxes 0.1
(1.2 )
Construction Expenditures Included in Current Liabilities as of March 31, 290.6
261.1

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~
~~110~~.

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales



	Three Months Ended March 31,
	2021	2020
	(in millions of KWhs)
Retail:
Residential	3,695	3,169
Commercial	1,457	1,477
Industrial	2,078	2,237
Miscellaneous	200	207
Total Retail	7,430	7,090

Wholesale	948	472

Total KWhs	8,378	7,562

Three Months Ended March 31,
2020 2019
(in millions of KWhs)
Retail:

Residential 3,169
3,587
Commercial 1,477
1,596
Industrial 2,237
2,336
Miscellaneous 207
219
Total Retail 7,090
7,738

Wholesale 472
816

Total KWhs 7,562
8,554

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2021	2020
	(in degree days)
Actual – Heating (a)	1,284	953
Normal – Heating (b)	1,315	1,324

Actual – Cooling (c)	4	20
Normal – Cooling (b)	6	6

(a)Heating degree days are calculated on a 55 degree temperature base.

(b)Normal Heating/Cooling represents the thirty-year average of degree days.

(c)Cooling degree days are calculated on a 65 degree temperature base.

Three Months Ended March 31,
2020 2019
(in degree days)
Actual – Heating (a) 953
1,252
Normal – Heating (b) 1,324
1,312

Actual – Cooling (c) 20
—
Normal – Cooling (b) 6
7


~~(a)~~	~~Heating degree days are calculated on a 55 degree temperature base.~~


~~(b)~~	~~Normal Heating/Cooling represents the thirty-year average of degree days.~~


~~(c)~~	~~Cooling degree days are calculated on a 65 degree temperature base.~~

First Quarter of ~~2020~~2021 Compared to First Quarter of ~~2019~~2020


Appalachian Power Company and Subsidiaries
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Net Income
(in millions)

First Quarter of 2020	$	115.3

Changes in Gross Margin:
Retail Margins	40.9
Margins from Off-system Sales	0.9
Transmission Revenues	7.1
Other Revenues	(1.7)
Total Change in Gross Margin	47.2

Changes in Expenses and Other:
Other Operation and Maintenance	(31.3)
Depreciation and Amortization	(13.6)
Taxes Other Than Income Taxes	0.2


Allowance for Equity Funds Used During Construction	1.1

Interest Expense	(1.8)
Total Change in Expenses and Other	(45.4)

Income Tax Expense	5.4

First Quarter of 2021	$	122.5

Reconciliation of First Quarter of 2019 to First Quarter of 2020
Net Income
(in millions)

First Quarter of 2019 $ 133.7

Changes in Gross Margin:
Retail Margins 14.3
Margins from Off-system Sales (0.6 )
Transmission Revenues 1.4
Other Revenues 1.8
Total Change in Gross Margin 16.9

Changes in Expenses and Other:
Other Operation and Maintenance 14.1
Depreciation and Amortization (9.7 )
Taxes Other Than Income Taxes (2.0 )
Interest Income (0.5 )
Allowance for Equity Funds Used During Construction 0.7
Non-Service Cost Components of Net Periodic Benefit Cost 0.4
Interest Expense (3.8 )
Total Change in Expenses and Other (0.8 )

Income Tax Expense (34.5 )

First Quarter of 2020 $ 115.3


•	•Retail Margins increased $41 million primarily due to the following: • ~~increased $14 million primarily due to the following:~~

A ~~$17~~$33 million increase in weather-related usage primarily driven by a 35% increase in heating degree days.

•A $14 million increase due to ~~customer refunds related to the 2018 Tax Reform.~~rider revenues primarily in West Virginia. This increase was partially offset in ~~Income Tax Expense (Benefit)~~other expense items below.

~~A $14~~These increases were partially offset by:

•An $8 million ~~increase~~decrease in ~~deferred fuel~~weather-normalized margins primarily in the commercial and industrial classes, partially offset in the residential class.

•Transmission Revenues increased $7 million primarily due to ~~the timing of recoverable PJM expenses.~~an increase in transmission investment. This increase ~~was offset in other expense items below.~~

A $12 million increase due to the impact of the 2019 WVPSC order which required the Company to offset Excess ADIT not subject to normalization requirements against the deferred fuel under-recovery balance in 2019.

~~A $10 million increase due to a base rate increase in West Virginia that was~~is partially offset in Depreciation and Amortization expenses below.

~~A $4 million increase due to revenue primarily from rate riders in West Virginia.~~

~~These increases were partially offset by:~~

~~A $33 million decrease in weather-related usage primarily driven by a 24% decrease in heating degree days.~~

~~A $9 million decrease in weather-normalized margins occurring across all retail classes.~~

Expenses and Other and Income Tax Expense ~~(Benefit)~~ changed between years as follows:

•

•Other Operation and Maintenance expenses increased $31 million primarily due to the following:

•A $13 million increase in distribution expense primarily due to vegetation management expenses. This increase was offset in Retail Margins above.

•A $10 million increase in transmission expenses primarily due to an $8 million increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.

•Depreciation and Amortization expenses increased $14 million primarily due to an increase in depreciation rates and a higher depreciable base. This increase is partially offset in Transmission Revenues above.

•Income Tax Expense decreased ~~$14 million primarily due to the following:~~

A $5 million ~~decrease~~primarily due to an increase in ~~maintenance expense at various generation plants.~~

~~A $5 million decrease~~amortization of Excess ADIT. The increase in ~~employee-related expenses.~~

~~A $4 million decrease in PJM expenses primarily related to the annual formula rate true-up.~~

~~A $4 million decrease in storm and vegetation management services.~~

~~These decreases were~~amortization of Excess ADIT is partially offset ~~by:~~above in Gross Margin.


��	~~A $5 million increase in recoverable PJM transmission expenses which were partially offset within Retail Margins above.~~


•	~~Depreciation and Amortization~~ expenses increased $10 million primarily due to a higher depreciable base and an increase in West Virginia depreciation rates beginning in March 2019. This increase was partially offset within Retail Margins above.


•	~~Interest Expense~~ ~~increased $4 million primarily due to higher long-term debt balances.~~


•	~~Income Tax Expense~~ ~~increased~~ $35 million primarily due to a decrease in amortization of excess ADIT and an increase in pretax book income. The decrease in amortization of excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Three Months Ended
	Three Months Ended March 31,
	2021		2020
REVENUES
Electric Generation, Transmission and Distribution	$	764.2	$	697.0
Sales to AEP Affiliates	50.1		49.7
Other Revenues	2.7		2.7
TOTAL REVENUES	817.0		749.4

EXPENSES
Fuel and Other Consumables Used for Electric Generation	163.9		111.0
Purchased Electricity for Resale	90.1		122.6


Other Operation	150.4		134.0
Maintenance	65.2		50.3
Depreciation and Amortization	135.8		122.2
Taxes Other Than Income Taxes	37.7		37.9
TOTAL EXPENSES	643.1		578.0

OPERATING INCOME	173.9		171.4

Other Income (Expense):
Interest Income	0.3		0.3

Allowance for Equity Funds Used During Construction	3.5		2.4
Non-Service Cost Components of Net Periodic Benefit Cost	4.7		4.7
Interest Expense	(54.9)		(53.1)

INCOME BEFORE INCOME TAX EXPENSE	127.5		125.7

Income Tax Expense	5.0		10.4

NET INCOME	$	122.5	$	115.3

The common stock of APCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Three Months Ended March 31,
2020 2019
REVENUES
Electric Generation, Transmission and Distribution $ 697.0
$ 738.7
Sales to AEP Affiliates 49.7
51.7
Other Revenues 2.7
2.4
TOTAL REVENUES 749.4
792.8

EXPENSES

Fuel and Other Consumables Used for Electric Generation 111.0
183.3
Purchased Electricity for Resale 122.6
110.6
Other Operation 134.0
136.9
Maintenance 50.3
61.5
Depreciation and Amortization 122.2
112.5
Taxes Other Than Income Taxes 37.9
35.9
TOTAL EXPENSES 578.0
640.7

OPERATING INCOME 171.4
152.1

Other Income (Expense):

Interest Income 0.3
0.8
Allowance for Equity Funds Used During Construction 2.4
1.7
Non-Service Cost Components of Net Periodic Benefit Cost 4.7
4.3
Interest Expense (53.1 ) (49.3 )

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 125.7
109.6

Income Tax Expense (Benefit) 10.4
(24.1 )

NET INCOME $ 115.3
$ 133.7



~~The common stock of APCo is wholly-owned by Parent.~~

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Three Months Ended
	March 31,
	2021		2020
Net Income	$	122.5	$	115.3

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $2.4 and $(1.1) in 2021 and 2020, Respectively	9.0		(4.2)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.3) and $(0.3) in 2021 and 2020, Respectively	(1.1)		(0.9)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	7.9		(5.1)

TOTAL COMPREHENSIVE INCOME	$	130.4	$	110.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Three Months Ended March 31,
2020 2019
Net Income $ 115.3
$ 133.7

OTHER COMPREHENSIVE LOSS, NET OF TAXES

Cash Flow Hedges, Net of Tax of $(1.1) and $(0.1) in 2020 and 2019, Respectively (4.2 ) (0.2 )
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.3) and $(0.2) in 2020 and 2019, Respectively (0.9 ) (0.6 )

TOTAL OTHER COMPREHENSIVE LOSS (5.1 ) (0.8 )

TOTAL COMPREHENSIVE INCOME $ 110.2
$ 132.9



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2019	$	260.4	$	1,828.7	$	2,078.3	$	5.0	$	4,172.4

Common Stock Dividends					(50.0)				(50.0)

Net Income					115.3				115.3
Other Comprehensive Loss							(5.1)		(5.1)










TOTAL COMMON SHAREHOLDER’S EQUITY - MARCH 31, 2020	$	260.4	$	1,828.7	$	2,143.6	$	(0.1)	$	4,232.6

TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020	$	260.4	$	1,828.7	$	2,248.0	$	7.2	$	4,344.3

Common Stock Dividends					(12.5)				(12.5)

Net Income					122.5				122.5
Other Comprehensive Income							7.9		7.9
TOTAL COMMON SHAREHOLDER’S EQUITY - MARCH 31, 2021	$	260.4	$	1,828.7	$	2,358.0	$	15.1	$	4,462.2












See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Common
Stock Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 $ 260.4
$ 1,828.7
$ 1,922.0
$ (5.0 ) $ 4,006.1

Common Stock Dividends (50.0 ) (50.0 )
Net Income 133.7
133.7
Other Comprehensive Loss (0.8 ) (0.8 )
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 $ 260.4
$ 1,828.7
$ 2,005.7
$ (5.8 ) $ 4,089.0

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019 $ 260.4
$ 1,828.7
$ 2,078.3
$ 5.0
$ 4,172.4

Common Stock Dividends (50.0 ) (50.0 )
Net Income 115.3
115.3
Other Comprehensive Loss (5.1 ) (5.1 )
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020 $ 260.4
$ 1,828.7
$ 2,143.6
$ (0.1 ) $ 4,232.6



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, ~~2020~~2021 and December 31, ~~2019~~2020

(in millions)

(Unaudited)


	March 31,		December 31,
	2021		2020
CURRENT ASSETS
Cash and Cash Equivalents	$	4.8	$	5.8
Restricted Cash for Securitized Funding	11.6		16.9
Advances to Affiliates	261.1		21.4
Accounts Receivable:
Customers	146.4		142.8
Affiliated Companies	64.9		64.3
Accrued Unbilled Revenues	50.7		80.1
Miscellaneous	0.3		0.3
Allowance for Uncollectible Accounts	(2.1)		(3.1)
Total Accounts Receivable	260.2		284.4
Fuel	166.9		193.6
Materials and Supplies	101.2		99.6
Risk Management Assets	6.9		22.4

Regulatory Asset for Under-Recovered Fuel Costs	15.3		5.3

Prepayments and Other Current Assets	24.7		24.7
TOTAL CURRENT ASSETS	852.7		674.1

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,643.9		6,633.7
Transmission	3,931.7		3,900.5
Distribution	4,511.5		4,464.3
Other Property, Plant and Equipment	644.2		627.2
Construction Work in Progress	525.9		484.6
Total Property, Plant and Equipment	16,257.2		16,110.3
Accumulated Depreciation and Amortization	4,802.0		4,716.2
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	11,455.2		11,394.1

OTHER NONCURRENT ASSETS
Regulatory Assets	727.1		686.3
Securitized Assets	203.9		210.1
Employee Benefits and Pension Assets	152.3		150.1

Operating Lease Assets	76.3		78.8
Deferred Charges and Other Noncurrent Assets	130.1		121.7
TOTAL OTHER NONCURRENT ASSETS	1,289.7		1,247.0

TOTAL ASSETS	$	13,597.6	$	13,315.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

March 31, December 31,
2020 2019
CURRENT ASSETS
Cash and Cash Equivalents $ 2.8
$ 3.3
Restricted Cash for Securitized Funding 15.7
23.5
Advances to Affiliates 21.8
22.1
Accounts Receivable:
Customers 132.6
129.0
Affiliated Companies 78.0
64.3
Accrued Unbilled Revenues 46.1
59.7
Miscellaneous 0.6
0.5
Allowance for Uncollectible Accounts (2.9 ) (2.6 )
Total Accounts Receivable 254.4
250.9
Fuel 160.0
149.7
Materials and Supplies 100.4
105.2
Risk Management Assets 18.1
39.4
Regulatory Asset for Under-Recovered Fuel Costs 34.9
42.5
Prepayments and Other Current Assets 33.1
64.0
TOTAL CURRENT ASSETS 641.2
700.6

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 6,602.1
6,563.7
Transmission 3,613.2
3,584.1
Distribution 4,279.1
4,201.7
Other Property, Plant and Equipment 585.5
571.3
Construction Work in Progress 574.0
593.4
Total Property, Plant and Equipment 15,653.9
15,514.2
Accumulated Depreciation and Amortization 4,497.0
4,432.3
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 11,156.9
11,081.9

OTHER NONCURRENT ASSETS
Regulatory Assets 464.0
457.2
Securitized Assets 228.5
234.7
Long-term Risk Management Assets 0.1
0.1
Operating Lease Assets 77.5
78.5
Deferred Charges and Other Noncurrent Assets 225.4
215.3
TOTAL OTHER NONCURRENT ASSETS 995.5
985.8

TOTAL ASSETS $ 12,793.6
$ 12,768.3



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, ~~2020~~2021 and December 31, ~~2019~~2020

(Unaudited)


	March 31,		December 31,
	2021		2020
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	0	$	18.6
Accounts Payable:
General	247.1		212.0
Affiliated Companies	99.3		97.1
Long-term Debt Due Within One Year – Nonaffiliated	168.5		518.3


Customer Deposits	75.0		77.8

Accrued Taxes	114.4		109.9
Accrued Interest	73.8		49.9
Obligations Under Operating Leases	14.9		14.9

Other Current Liabilities	107.9		119.2
TOTAL CURRENT LIABILITIES	900.9		1,217.7

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	4,797.7		4,315.8



Deferred Income Taxes	1,763.1		1,749.9
Regulatory Liabilities and Deferred Investment Tax Credits	1,215.6		1,224.7
Asset Retirement Obligations	305.5		304.8
Employee Benefits and Pension Obligations	44.0		44.0
Obligations Under Operating Leases	61.9		64.4
Deferred Credits and Other Noncurrent Liabilities	46.7		49.6
TOTAL NONCURRENT LIABILITIES	8,234.5		7,753.2

TOTAL LIABILITIES	9,135.4		8,970.9

Rate Matters (Note 4)	0		0
Commitments and Contingencies (Note 5)	0		0

COMMON SHAREHOLDER’S EQUITY
Common Stock – NaN Par Value:
Authorized – 30,000,000 Shares
Outstanding – 13,499,500 Shares	260.4		260.4
Paid-in Capital	1,828.7		1,828.7
Retained Earnings	2,358.0		2,248.0
Accumulated Other Comprehensive Income (Loss)	15.1		7.2
TOTAL COMMON SHAREHOLDER’S EQUITY	4,462.2		4,344.3

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	13,597.6	$	13,315.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

March 31, December 31,
2020 2019
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ 355.3
$ 236.7
Accounts Payable:

General 198.7
307.8
Affiliated Companies 75.2
92.5
Long-term Debt Due Within One Year – Nonaffiliated 583.3
215.6
Risk Management Liabilities 15.0
1.9
Customer Deposits 84.5
85.8
Accrued Taxes 102.7
99.6
Accrued Interest 67.0
47.9
Obligations Under Operating Leases 15.4
15.2
Other Current Liabilities 90.1
123.0
TOTAL CURRENT LIABILITIES 1,587.2
1,226.0

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated 3,769.1
4,148.2
Long-term Risk Management Liabilities 0.1
—
Deferred Income Taxes 1,680.9
1,680.8
Regulatory Liabilities and Deferred Investment Tax Credits 1,254.5
1,268.7
Asset Retirement Obligations 103.6
102.1
Employee Benefits and Pension Obligations 47.3
50.9
Obligations Under Operating Leases 63.1
64.0
Deferred Credits and Other Noncurrent Liabilities 55.2
55.2
TOTAL NONCURRENT LIABILITIES 6,973.8
7,369.9

TOTAL LIABILITIES 8,561.0
8,595.9

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares

Outstanding – 13,499,500 Shares 260.4
260.4
Paid-in Capital 1,828.7
1,828.7
Retained Earnings 2,143.6
2,078.3
Accumulated Other Comprehensive Income (Loss) (0.1 ) 5.0
TOTAL COMMON SHAREHOLDER’S EQUITY 4,232.6
4,172.4

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 12,793.6
$ 12,768.3



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2021		2020
OPERATING ACTIVITIES
Net Income	$	122.5	$	115.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	135.8		122.2
Deferred Income Taxes	(1.7)		(5.1)


Allowance for Equity Funds Used During Construction	(3.5)		(2.4)
Mark-to-Market of Risk Management Contracts	12.1		29.6


Deferred Fuel Over/Under-Recovery, Net	(6.4)		7.6
Change in Other Noncurrent Assets	(54.3)		(24.4)
Change in Other Noncurrent Liabilities	6.8		(16.1)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	25.1		(2.6)
Fuel, Materials and Supplies	25.2		(5.5)
Accounts Payable	46.0		(86.6)
Accrued Taxes, Net	8.2		14.5
Other Current Assets	(3.6)		19.2
Other Current Liabilities	3.1		(11.1)
Net Cash Flows from Operating Activities	315.3		154.6

INVESTING ACTIVITIES
Construction Expenditures	(187.5)		(219.1)

Change in Advances to Affiliates, Net	(239.7)		0.3

Other Investing Activities	6.6		1.1
Net Cash Flows Used for Investing Activities	(420.6)		(217.7)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	494.3		0
Change in Advances from Affiliates, Net	(18.6)		118.6
Retirement of Long-term Debt – Nonaffiliated	(362.5)		(12.2)


Principal Payments for Finance Lease Obligations	(1.9)		(1.8)
Dividends Paid on Common Stock	(12.5)		(50.0)
Other Financing Activities	0.2		0.2
Net Cash Flows from Financing Activities	99.0		54.8

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	(6.3)		(8.3)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	22.7		26.8
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	16.4	$	18.5

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	28.9	$	31.9

Noncash Acquisitions Under Finance Leases	0.4		1.9
Construction Expenditures Included in Current Liabilities as of March 31,	96.1		103.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Three Months Ended March 31,
2020 2019
OPERATING ACTIVITIES

Net Income $ 115.3
$ 133.7
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

Depreciation and Amortization 122.2
112.5
Deferred Income Taxes (5.1 ) (45.0 )
Allowance for Equity Funds Used During Construction (2.4 ) (1.7 )
Mark-to-Market of Risk Management Contracts 29.6
50.6
Deferred Fuel Over/Under-Recovery, Net 7.6
20.8
Change in Other Noncurrent Assets (24.4 ) (12.1 )
Change in Other Noncurrent Liabilities (16.1 ) (20.5 )
Changes in Certain Components of Working Capital:

Accounts Receivable, Net (2.6 ) 19.5
Fuel, Materials and Supplies (5.5 ) (9.6 )
Accounts Payable (86.6 ) (8.3 )
Accrued Taxes, Net 14.5
13.7
Other Current Assets 19.2
(0.8 )
Other Current Liabilities (11.1 ) (2.3 )
Net Cash Flows from Operating Activities 154.6
250.5

INVESTING ACTIVITIES

Construction Expenditures (219.1 ) (205.1 )
Change in Advances to Affiliates, Net 0.3
(193.6 )
Other Investing Activities 1.1
15.2
Net Cash Flows Used for Investing Activities (217.7 ) (383.5 )

FINANCING ACTIVITIES

Issuance of Long-term Debt – Nonaffiliated —
393.3
Change in Advances from Affiliates, Net 118.6
(205.6 )
Retirement of Long-term Debt – Nonaffiliated (12.2 ) (12.0 )
Principal Payments for Finance Lease Obligations (1.8 ) (1.6 )
Dividends Paid on Common Stock (50.0 ) (50.0 )
Other Financing Activities 0.2
0.3
Net Cash Flows from Financing Activities 54.8
124.4

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (8.3 ) (8.6 )
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 26.8
29.8
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $ 18.5
$ 21.2

SUPPLEMENTARY INFORMATION

Cash Paid for Interest, Net of Capitalized Amounts $ 31.9
$ 14.5
Net Cash Paid for Income Taxes —
8.0
Noncash Acquisitions Under Finance Leases 1.9
2.1
Construction Expenditures Included in Current Liabilities as of March 31, 103.7
87.8



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales



	Three Months Ended March 31,
	2021	2020
	(in millions of KWhs)
Retail:
Residential	1,532	1,455
Commercial	1,078	1,122
Industrial	1,802	1,845
Miscellaneous	17	18
Total Retail	4,429	4,440

Wholesale	1,945	1,693

Total KWhs	6,374	6,133

Three Months Ended March 31,
2020 2019
(in millions of KWhs)
Retail:

Residential 1,455
1,615
Commercial 1,122
1,156
Industrial 1,845
1,888
Miscellaneous 18
19
Total Retail 4,440
4,678

Wholesale 1,693
2,423

Total KWhs 6,133
7,101

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2021	2020
	(in degree days)
Actual – Heating (a)	2,056	1,836
Normal – Heating (b)	2,170	2,182

Actual – Cooling (c)	—	—
Normal – Cooling (b)	1	2

(a)Heating degree days are calculated on a 55 degree temperature base.

(b)Normal Heating/Cooling represents the thirty-year average of degree days.

(c)Cooling degree days are calculated on a 65 degree temperature base.

Three Months Ended March 31,
2020 2019
(in degree days)
Actual – Heating (a) 1,836
2,239
Normal – Heating (b) 2,182
2,160

Actual – Cooling (c) —
—
Normal – Cooling (b) 2
2


~~(a)~~	~~Heating degree days are calculated on a 55 degree temperature base.~~


~~(b)~~	~~Normal Heating/Cooling represents the thirty-year average of degree days.~~


~~(c)~~	~~Cooling degree days are calculated on a 65 degree temperature base.~~

First Quarter of ~~2020~~2021 Compared to First Quarter of ~~2019~~2020


Indiana Michigan Power Company and Subsidiaries
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Net Income
(in millions)

First Quarter of 2020	$	92.3

Changes in Gross Margin:
Retail Margins	(2.6)

Margins from Off-system Sales	(0.3)
Transmission Revenues	(0.5)
Other Revenues	1.9
Total Change in Gross Margin	(1.5)

Changes in Expenses and Other:
Other Operation and Maintenance	(9.8)

Depreciation and Amortization	(15.3)
Taxes Other Than Income Taxes	0.2
Other Income	0.5


Non-Service Cost Components of Net Periodic Benefit Cost	(0.1)
Interest Expense	3.4
Total Change in Expenses and Other	(21.1)

Income Tax Expense	1.1

First Quarter of 2021	$	70.8

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

•Retail Margins decreased $3 million primarily due to the following:

•A $16 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract.

•A $7 million decrease in weather-normalized retail margins.

These decreases were partially offset by:

•A $12 million increase due to the Indiana and Michigan base rate cases and rider revenues. This increase was partially offset in other expense items below.

•An $8 million increase in weather-related usage primarily due to a 12% increase in heating degree days.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $10 million primarily due to the following:

•A $9 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.

•A $4 million increase due to a decreased Nuclear Electric Insurance Limited distribution in 2021.

•A $4 million increase in employee-related expenses.

These increases were partially offset by:

•A $5 million decrease in customer service and information expenses primarily due to an Indiana order to refund an over collection of Demand Side Management expenses. This decrease was offset in Retail Margins above.

•A $3 million decrease in Cook Plant refueling outage expenses.

•Depreciation and Amortization expensesincreased $15 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.

•Interest Expense decreased $3 million primarily due to a decrease in interest rates on variable rate notes.

Reconciliation of First Quarter of 2019 to First Quarter of 2020
Net Income
(in millions)

First Quarter of 2019 $ 98.9

Changes in Gross Margin:
Retail Margins 2.7
Margins from Off-system Sales 0.1
Transmission Revenues 1.4
Other Revenues (0.7 )
Total Change in Gross Margin 3.5

Changes in Expenses and Other:
Other Operation and Maintenance 5.0
Depreciation and Amortization (7.7 )
Taxes Other Than Income Taxes 0.9
Other Income (3.2 )
Non-Service Cost Components of Net Periodic Benefit Cost (0.2 )
Interest Expense (1.8 )
Total Change in Expenses and Other (7.0 )

Income Tax Expense (3.1 )

First Quarter of 2020 $ 92.3

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2021 and 2020

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2021		2020
REVENUES
Electric Generation, Transmission and Distribution	$	547.7	$	553.4
Sales to AEP Affiliates	0.8		2.9
Other Revenues – Affiliated	14.3		12.5
Other Revenues – Nonaffiliated	1.7		1.5
TOTAL REVENUES	564.5		570.3

EXPENSES
Fuel and Other Consumables Used for Electric Generation	36.3		53.2
Purchased Electricity for Resale	47.3		50.1
Purchased Electricity from AEP Affiliates	51.6		36.2
Other Operation	154.6		144.7
Maintenance	49.0		49.1

Depreciation and Amortization	109.2		93.9
Taxes Other Than Income Taxes	26.2		26.4
TOTAL EXPENSES	474.2		453.6

OPERATING INCOME	90.3		116.7

Other Income (Expense):
Other Income	3.0		2.5


Non-Service Cost Components of Net Periodic Benefit Cost	4.1		4.2
Interest Expense	(27.3)		(30.7)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	70.1		92.7

Income Tax Expense (Benefit)	(0.7)		0.4

NET INCOME	$	70.8	$	92.3

The common stock of I&M is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2021 and 2020

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2021		2020
Net Income	$	70.8	$	92.3

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2021 and 2020, Respectively	0.5		0.4




TOTAL COMPREHENSIVE INCOME	$	71.3	$	92.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 2021 and 2020

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2019	$	56.6	$	980.9	$	1,518.5	$	(11.6)	$	2,544.4

Common Stock Dividends					(21.3)				(21.3)
ASU 2016-13 Adoption					0.4				0.4
Net Income					92.3				92.3
Other Comprehensive Income							0.4		0.4
TOTAL COMMON SHAREHOLDER’S EQUITY - MARCH 31, 2020	$	56.6	$	980.9	$	1,589.9	$	(11.2)	$	2,616.2











TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020	$	56.6	$	980.9	$	1,718.7	$	(7.0)	$	2,749.2

Common Stock Dividends					(25.0)				(25.0)

Net Income					70.8				70.8
Other Comprehensive Income							0.5		0.5
TOTAL COMMON SHAREHOLDER’S EQUITY - MARCH 31, 2021	$	56.6	$	980.9	$	1,764.5	$	(6.5)	$	2,795.5











See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2021 and December 31, 2020

(in millions)

(Unaudited)


	March 31,		December 31,
	2021		2020
CURRENT ASSETS
Cash and Cash Equivalents	$	2.8	$	3.3
Advances to Affiliates	13.3		13.3
Accounts Receivable:
Customers	32.7		44.0
Affiliated Companies	48.8		51.3
Accrued Unbilled Revenues	0.4		0
Miscellaneous	1.6		2.0
Allowance for Uncollectible Accounts	(0.4)		(0.3)
Total Accounts Receivable	83.1		97.0
Fuel	80.2		86.0
Materials and Supplies	172.8		175.8
Risk Management Assets	0.9		3.6
Accrued Tax Benefits	1.0		10.3
Regulatory Asset for Under-Recovered Fuel Costs	3.2		5.4


Prepayments and Other Current Assets	17.9		24.1
TOTAL CURRENT ASSETS	375.2		418.8

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	5,302.4		5,264.7
Transmission	1,696.9		1,696.4
Distribution	2,634.3		2,594.6
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	707.4		686.7
Construction Work in Progress	369.5		362.4
Total Property, Plant and Equipment	10,710.5		10,604.8
Accumulated Depreciation, Depletion and Amortization	3,647.3		3,552.5
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	7,063.2		7,052.3

OTHER NONCURRENT ASSETS
Regulatory Assets	403.4		404.8
Spent Nuclear Fuel and Decommissioning Trusts	3,414.3		3,306.7

Operating Lease Assets	196.8		218.1
Deferred Charges and Other Noncurrent Assets	241.3		237.6
TOTAL OTHER NONCURRENT ASSETS	4,255.8		4,167.2

TOTAL ASSETS	$	11,694.2	$	11,638.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2021 and December 31, 2020

(dollars in millions)

(Unaudited)


	March 31,		December 31,
	2021		2020
CURRENT LIABILITIES
Advances from Affiliates	$	124.6	$	103.0
Accounts Payable:
General	113.7		153.2
Affiliated Companies	70.9		80.5
Long-term Debt Due Within One Year – Nonaffiliated (March 31, 2021 and December 31, 2020 Amounts Include $69.2 and $75.7, Respectively, Related to DCC Fuel)	363.1		369.6

Customer Deposits	43.5		41.7
Accrued Taxes	114.8		102.5
Accrued Interest	19.7		35.6
Obligations Under Operating Leases	85.5		85.6
Regulatory Liability for Over-Recovered Fuel Costs	9.3		20.8
Other Current Liabilities	82.6		112.0
TOTAL CURRENT LIABILITIES	1,027.7		1,104.5

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,643.2		2,660.3

Deferred Income Taxes	1,064.9		1,064.4
Regulatory Liabilities and Deferred Investment Tax Credits	2,111.8		2,041.9
Asset Retirement Obligations	1,830.9		1,812.9
Obligations Under Operating Leases	131.3		135.9
Deferred Credits and Other Noncurrent Liabilities	88.9		69.2
TOTAL NONCURRENT LIABILITIES	7,871.0		7,784.6

TOTAL LIABILITIES	8,898.7		8,889.1

Rate Matters (Note 4)	0		0
Commitments and Contingencies (Note 5)	0		0

COMMON SHAREHOLDER’S EQUITY
Common Stock – NaN Par Value:
Authorized – 2,500,000 Shares
Outstanding – 1,400,000 Shares	56.6		56.6
Paid-in Capital	980.9		980.9
Retained Earnings	1,764.5		1,718.7
Accumulated Other Comprehensive Income (Loss)	(6.5)		(7.0)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,795.5		2,749.2

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	11,694.2	$	11,638.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2021 and 2020

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2021		2020
OPERATING ACTIVITIES
Net Income	$	70.8	$	92.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	109.2		93.9
Rockport Plant, Unit 2 Operating Lease Amortization	16.6		17.3
Deferred Income Taxes	(12.1)		(16.3)
Amortization of Incremental Nuclear Refueling Outage Expenses, Net	4.9		15.2


Allowance for Equity Funds Used During Construction	(3.5)		(2.0)
Mark-to-Market of Risk Management Contracts	2.7		4.4
Amortization of Nuclear Fuel	22.7		23.4

Deferred Fuel Over/Under-Recovery, Net	(9.3)		22.5
Change in Other Noncurrent Assets	2.6		(2.9)
Change in Other Noncurrent Liabilities	24.1		10.0
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	14.4		8.6
Fuel, Materials and Supplies	8.8		(16.2)

Accounts Payable	(14.8)		(21.6)

Accrued Taxes, Net	21.6		25.0


Other Current Assets	5.2		18.2
Other Current Liabilities	(45.8)		(62.7)
Net Cash Flows from Operating Activities	218.1		209.1

INVESTING ACTIVITIES
Construction Expenditures	(120.2)		(141.4)
Change in Advances to Affiliates, Net	0		(0.1)
Purchases of Investment Securities	(336.9)		(626.0)
Sales of Investment Securities	320.0		612.4
Acquisitions of Nuclear Fuel	(55.9)		(1.3)

Other Investing Activities	3.2		4.2
Net Cash Flows Used for Investing Activities	(189.8)		(152.2)

FINANCING ACTIVITIES

Change in Advances from Affiliates, Net	21.6		(10.7)
Retirement of Long-term Debt – Nonaffiliated	(24.1)		(23.7)
Principal Payments for Finance Lease Obligations	(1.5)		(1.5)
Dividends Paid on Common Stock	(25.0)		(21.3)
Other Financing Activities	0.2		0.1
Net Cash Flows Used for Financing Activities	(28.8)		(57.1)

Net Decrease in Cash and Cash Equivalents	(0.5)		(0.2)
Cash and Cash Equivalents at Beginning of Period	3.3		2.0
Cash and Cash Equivalents at End of Period	$	2.8	$	1.8

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	42.0	$	44.3

Noncash Acquisitions Under Finance Leases	2.4		1.4
Construction Expenditures Included in Current Liabilities as of March 31,	50.5		67.8
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,	6.7		0
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage	0.1		1.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

OHIO POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales



	Three Months Ended March 31,
	2021	2020
	(in millions of KWhs)
Retail:
Residential	4,106	3,834
Commercial	3,502	3,516
Industrial	3,401	3,543
Miscellaneous	29	30
Total Retail (a)	11,038	10,923

Wholesale (b)	603	390

Total KWhs	11,641	11,313

(a)Represents energy delivered to distribution customers.

(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2021	2020
	(in degree days)
Actual – Heating (a)	1,777	1,473
Normal – Heating (b)	1,883	1,898

Actual – Cooling (c)	—	3
Normal – Cooling (b)	3	3

(a)Heating degree days are calculated on a 55 degree temperature base.

(b)Normal Heating/Cooling represents the thirty-year average of degree days.

(c)Cooling degree days are calculated on a 65 degree temperature base.

First Quarter of 2021 Compared to First Quarter of 2020


Ohio Power Company and Subsidiaries
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Net Income
(in millions)

First Quarter of 2020	$	75.1

Changes in Gross Margin:
Retail Margins	31.1
Margins from Off-system Sales	(14.0)
Transmission Revenues	(2.9)
Other Revenues	5.5
Total Change in Gross Margin	19.7

Changes in Expenses and Other:
Other Operation and Maintenance	(14.4)
Depreciation and Amortization	(4.6)
Taxes Other Than Income Taxes	(9.3)

Carrying Costs Income	0.1
Allowance for Equity Funds Used During Construction	0.8
Non-Service Cost Components of Net Periodic Benefit Cost	(0.1)
Interest Expense	(2.7)
Total Change in Expenses and Other	(30.2)

Income Tax Expense	3.6

First Quarter of 2021	$	68.2

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:

•Retail Margins increased $31 million primarily due to the following:

•A $58 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.

•A $6 million increase in the Legacy Generation Resource Rider (LGRR). This increase was offset in Margins from Off-system Sales and Other Revenues below.

•A $5 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.

•A $5 million increase in revenues associated with a vegetation management rider. This increase was partially offset in Other Operation and Maintenance expenses below.

These increases were partially offset by:

•A $27 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.

•A $16 million decrease in revenues associated with the Universal Service Fund (USF). This decrease was offset in Other Operation and Maintenance expenses below.

•Margins from Off-system Sales decreased $14 million primarily due to unfavorable deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.

•Other Revenues increased $6 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins and Margins from Off-system Sales above.

Expenses and Other and Income Tax Expense changed between years as follows:

•Other Operation and Maintenance expenses increased $14 million primarily due to the following:

•A $51 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase was offset in Retail Margins above.

•A $5 million increase in recoverable distribution expenses primarily related to vegetation management. This increase was offset in Retail Margins above.

These increases were partially offset by:

•A $22 million decrease in energy efficiency/demand side management expenses. This decrease was partially offset within Retail Margins above.

•A $16 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset in Retail Margins above.

•A $7 million decrease in factored Customers Accounts Receivable expenses primarily due to a current year adjustment to allowance for doubtful accounts.

•Depreciation and Amortization expensesincreased $5 million primarily due to a higher depreciable base of transmission and distribution assets.

•Taxes Other Than Income Taxes increased $9 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

•Income Tax Expense decreased $4 million primarily due to a favorable prior period adjustment recognized in 2021 and a decrease in pretax book income.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2021 and 2020

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2021		2020
REVENUES
Electricity, Transmission and Distribution	$	716.7	$	679.2
Sales to AEP Affiliates	4.8		8.4
Other Revenues	2.4		2.7
TOTAL REVENUES	723.9		690.3

EXPENSES
Purchased Electricity for Resale	175.3		149.1
Purchased Electricity from AEP Affiliates	30.1		42.4

Other Operation	184.6		177.3
Maintenance	38.7		31.6
Depreciation and Amortization	75.1		70.5
Taxes Other Than Income Taxes	121.3		112.0
TOTAL EXPENSES	625.1		582.9

OPERATING INCOME	98.8		107.4

Other Income (Expense):
Interest Income	0.2		0.2
Carrying Costs Income	0.5		0.4
Allowance for Equity Funds Used During Construction	2.7		1.9
Non-Service Cost Components of Net Periodic Benefit Cost	3.7		3.8
Interest Expense	(31.6)		(28.9)

INCOME BEFORE INCOME TAX EXPENSE	74.3		84.8

Income Tax Expense	6.1		9.7

NET INCOME	$	68.2	$	75.1

The common stock of OPCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2021 and 2020

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2021		2020
Net Income	$	68.2	$	75.1

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 in 2021 and 2020, Respectively	0		0

TOTAL COMPREHENSIVE INCOME	$	68.2	$	75.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 2021 and 2020

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019	$	321.2	$	838.8	$	1,348.5	$	0	$	2,508.5

Common Stock Dividends					(21.9)				(21.9)
ASU 2016-13 Adoption					0.3				0.3
Net Income					75.1				75.1

TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020	$	321.2	$	838.8	$	1,402.0	$	0	$	2,562.0











TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020	$	321.2	$	838.8	$	1,532.7	$	0	$	2,692.7

Common Stock Dividends					(21.9)				(21.9)
Net Income					68.2				68.2

TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021	$	321.2	$	838.8	$	1,579.0	$	0	$	2,739.0











See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2021 and December 31, 2020

(in millions)

(Unaudited)


	March 31,		December 31,
	2021		2020
CURRENT ASSETS
Cash and Cash Equivalents	$	6.1	$	7.4
Advances to Affiliates	0.5		0
Accounts Receivable:
Customers	66.1		50.0
Affiliated Companies	78.3		65.1
Accrued Unbilled Revenues	15.3		14.8
Miscellaneous	7.2		3.9
Allowance for Uncollectible Accounts	(0.7)		(0.6)
Total Accounts Receivable	166.2		133.2
Materials and Supplies	67.3		66.9
Renewable Energy Credits	32.0		29.5



Prepayments and Other Current Assets	22.4		19.3
TOTAL CURRENT ASSETS	294.5		256.3

PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	2,862.7		2,831.9
Distribution	5,806.3		5,708.3
Other Property, Plant and Equipment	938.3		899.6
Construction Work in Progress	343.8		362.3
Total Property, Plant and Equipment	9,951.1		9,802.1
Accumulated Depreciation and Amortization	2,385.4		2,350.0
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	7,565.7		7,452.1

OTHER NONCURRENT ASSETS
Regulatory Assets	392.3		385.8

Deferred Charges and Other Noncurrent Assets	536.2		616.2
TOTAL OTHER NONCURRENT ASSETS	928.5		1,002.0

TOTAL ASSETS	$	8,788.7	$	8,710.4

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2021 and December 31, 2020

(dollars in millions)

(Unaudited)


	March 31,		December 31,
	2021		2020
CURRENT LIABILITIES
Advances from Affiliates	$	0	$	259.2
Accounts Payable:
General	174.5		181.0
Affiliated Companies	117.7		118.4
Long-term Debt Due Within One Year – Nonaffiliated	500.1		500.1
Risk Management Liabilities	8.1		8.7
Customer Deposits	54.3		55.1
Accrued Taxes	484.7		631.0

Obligations Under Operating Leases	13.1		13.1
Other Current Liabilities	132.0		139.6
TOTAL CURRENT LIABILITIES	1,484.5		1,906.2

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,376.2		1,930.1
Long-term Risk Management Liabilities	95.9		101.6
Deferred Income Taxes	968.8		955.1
Regulatory Liabilities and Deferred Investment Tax Credits	1,008.4		1,005.2

Obligations Under Operating Leases	77.0		79.5
Deferred Credits and Other Noncurrent Liabilities	38.9		40.0
TOTAL NONCURRENT LIABILITIES	4,565.2		4,111.5

TOTAL LIABILITIES	6,049.7		6,017.7

Rate Matters (Note 4)	0		0
Commitments and Contingencies (Note 5)	0		0

COMMON SHAREHOLDER’S EQUITY
Common Stock –NaN Par Value:
Authorized – 40,000,000 Shares
Outstanding – 27,952,473 Shares	321.2		321.2
Paid-in Capital	838.8		838.8
Retained Earnings	1,579.0		1,532.7

TOTAL COMMON SHAREHOLDER’S EQUITY	2,739.0		2,692.7

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	8,788.7	$	8,710.4

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2021 and 2020

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2021		2020
OPERATING ACTIVITIES
Net Income	$	68.2	$	75.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	75.1		70.5
Deferred Income Taxes	4.5		12.9

Allowance for Equity Funds Used During Construction	(2.7)		(1.9)
Mark-to-Market of Risk Management Contracts	(6.3)		17.3

Property Taxes	78.3		74.4

Change in Other Noncurrent Assets	(20.9)		(61.5)
Change in Other Noncurrent Liabilities	3.8		(36.4)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(31.8)		(19.9)
Materials and Supplies	(3.7)		(10.2)
Accounts Payable	(6.4)		35.5
Accrued Taxes, Net	(144.7)		(141.9)
Other Current Assets	(0.2)		(2.0)
Other Current Liabilities	(2.0)		(8.4)
Net Cash Flows from Operating Activities	11.2		3.5

INVESTING ACTIVITIES
Construction Expenditures	(178.2)		(232.8)
Change in Advances to Affiliates, Net	(0.5)		0
Other Investing Activities	2.6		5.9
Net Cash Flows Used for Investing Activities	(176.1)		(226.9)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	445.8		347.1
Change in Advances from Affiliates, Net	(259.2)		(101.6)

Principal Payments for Finance Lease Obligations	(1.2)		(1.2)
Dividends Paid on Common Stock	(21.9)		(21.9)
Other Financing Activities	0.1		0.4
Net Cash Flows from Financing Activities	163.6		222.8

Net Decrease in Cash and Cash Equivalents	(1.3)		(0.6)
Cash and Cash Equivalents at Beginning of Period	7.4		3.7
Cash and Cash Equivalents at End of Period	$	6.1	$	3.1

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	15.8	$	16.7

Noncash Acquisitions Under Finance Leases	0.4		4.3
Construction Expenditures Included in Current Liabilities as of March 31,	72.4		72.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales



	Three Months Ended March 31,
	2021	2020
	(in millions of KWhs)
Retail:
Residential	1,577	1,362
Commercial	1,050	1,055
Industrial	1,304	1,437
Miscellaneous	270	272
Total Retail	4,201	4,126

Wholesale	67	53

Total KWhs	4,268	4,179

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2021	2020
	(in degree days)
Actual – Heating (a)	1,150	799
Normal – Heating (b)	1,033	1,034

Actual – Cooling (c)	7	33
Normal – Cooling (b)	17	17

(a)Heating degree days are calculated on a 55 degree temperature base.

(b)Normal Heating/Cooling represents the thirty-year average of degree days.

(c)Cooling degree days are calculated on a 65 degree temperature base.

First Quarter of 2021 Compared to First Quarter of 2020


Public Service Company of Oklahoma
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Net Loss
(in millions)

First Quarter of 2020	$	(10.3)

Changes in Gross Margin:
Retail Margins (a)	4.2
Margins from Off-system Sales	(0.1)
Transmission Revenues	1.0
Other Revenues	0.1
Total Change in Gross Margin	5.2

Changes in Expenses and Other:
Other Operation and Maintenance	8.1
Depreciation and Amortization	(5.2)
Taxes Other Than Income Taxes	(1.2)


Allowance for Equity Funds Used During Construction	(0.6)


Interest Expense	1.4
Total Change in Expenses and Other	2.5

Income Tax Expense	(0.1)

First Quarter of 2021	$	(2.7)

(a)Includes firm wholesale sales to municipals and cooperatives.


•	•Retail Margins increased $4 million primarily due to the following: • ~~increased $3 million primarily due to the following:~~

A ~~$14~~$3 million increase in weather-related usage due to a 44% increase in heating degree days.

•A $2 million increase in revenue from rate ~~proceedings.~~riders. This increase was partially offset in other expense items below.

~~An $11 million increase related to fuel, primarily due to the timing of recoverable PJM expenses. This increase was partially offset in other expense items below.~~

~~A $4 million increase due to decreased costs for power acquired under the UPA between AEGCo and I&M.~~

~~A $3 million decrease in fuel-related expenses due to timing of recovery for fuel and other variable production costs related to wholesale contracts.~~

~~These increases were partially offset by:~~

~~A $16 million decrease in weather-normalized margins.~~

~~A $14 million decrease in weather-related usage primarily due to an 18% decrease in heating degree days.~~

Expenses and Other ~~and Income Tax Expense~~ changed between years as follows:


•	~~Other Operation and Maintenance~~ ~~expenses decreased $5~~ •Other Operation and Maintenance expenses decreased $8 million primarily ~~due to the following:~~

~~A $7 million decrease~~ due to ~~an increased Nuclear Electric Insurance Limited distribution in 2020.~~

~~A $5 million~~a decrease in employee-related expenses.

~~A $2~~•Depreciation and Amortization increased $5 million ~~decrease in vegetation management expenses.~~

~~A $2 million decrease in Cook Plant refueling outage amortization expense,~~ primarily due to ~~decreased costs~~a higher depreciable base and amortization of ~~outages.~~

~~These decreases were partially offset by:~~

~~An $11 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.~~


•	~~Depreciation and Amortization~~protected Excess ADIT.~~expensesincreased~~ ~~$8 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.~~


•	~~Other Income~~ ~~decreased~~ ~~$3 million primarily due to AFUDC adjustments that resulted from 2019 FERC audit findings.~~


•	~~Income Tax Expense~~ ~~increased $3 million primarily due to the recognition of a discrete tax adjustment and a decrease in favorable flow through tax benefits.~~

~~INDIANA MICHIGAN POWER~~PUBLIC SERVICE COMPANY ~~AND SUBSIDIARIES~~OF OKLAHOMA

CONDENSED ~~CONSOLIDATED~~ STATEMENTS OF ~~INCOME~~OPERATIONS

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Three Months Ended March 31,

	2021		2020
REVENUES
Electric Generation, Transmission and Distribution	$	293.6	$	295.4
Sales to AEP Affiliates	1.0		1.1
Other Revenues	1.5		0.8
TOTAL REVENUES	296.1		297.3

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	120.9		127.3


Other Operation	79.1		87.2
Maintenance	24.4		24.4
Depreciation and Amortization	49.9		44.7
Taxes Other Than Income Taxes	12.5		11.3
TOTAL EXPENSES	286.8		294.9

OPERATING INCOME	9.3		2.4

Other Income (Expense):
Interest Income	0.1		0.1

Allowance for Equity Funds Used During Construction	0.4		1.0

Non-Service Cost Components of Net Periodic Benefit Cost	2.1		2.1
Interest Expense	(14.4)		(15.8)

LOSS BEFORE INCOME TAX EXPENSE	(2.5)		(10.2)

Income Tax Expense	0.2		0.1

NET LOSS	$	(2.7)	$	(10.3)

The common stock of PSO is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

Three Months Ended March 31,
2020 2019
REVENUES
Electric Generation, Transmission and Distribution $ 553.4
$ 596.7
Sales to AEP Affiliates 2.9
2.3
Other Revenues – Affiliated 12.5
13.3
Other Revenues – Nonaffiliated 1.5
2.0
TOTAL REVENUES 570.3
614.3

EXPENSES

Fuel and Other Consumables Used for Electric Generation 53.2
57.6
Purchased Electricity for Resale 50.1
69.6
Purchased Electricity from AEP Affiliates 36.2
59.8
Other Operation 144.7
140.5
Maintenance 49.1
58.3
Depreciation and Amortization 93.9
86.2
Taxes Other Than Income Taxes 26.4
27.3
TOTAL EXPENSES 453.6
499.3

OPERATING INCOME 116.7
115.0

Other Income (Expense):

Other Income 2.5
5.7
Non-Service Cost Components of Net Periodic Benefit Cost 4.2
4.4
Interest Expense (30.7 ) (28.9 )

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 92.7
96.2

Income Tax Expense (Benefit) 0.4
(2.7 )

NET INCOME $ 92.3
$ 98.9

~~The common stock of I&M is wholly-owned by Parent.~~

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~INDIANA MICHIGAN POWER~~PUBLIC SERVICE COMPANY ~~AND SUBSIDIARIES~~OF OKLAHOMA

CONDENSED ~~CONSOLIDATED~~ STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Three Months Ended March 31,

	2021		2020
Net Loss	$	(2.7)	$	(10.3)

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $(0.1) in 2021 and 2020, Respectively	(0.1)		(0.2)

TOTAL COMPREHENSIVE LOSS	$	(2.8)	$	(10.5)

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

100

Three Months Ended March 31,
2020 2019
Net Income $ 92.3
$ 98.9

OTHER COMPREHENSIVE INCOME, NET OF TAXES

Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2020 and 2019, Respectively 0.4
0.4

TOTAL COMPREHENSIVE INCOME $ 92.7
$ 99.3

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~INDIANA MICHIGAN POWER~~PUBLIC SERVICE COMPANY ~~AND SUBSIDIARIES~~OF OKLAHOMA

CONDENSED ~~CONSOLIDATED~~ STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019	$	157.2	$	364.0	$	851.0	$	1.1	$	1,373.3


ASU 2016-13 Adoption					0.3				0.3
Net Loss					(10.3)				(10.3)
Other Comprehensive Loss							(0.2)		(0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020	$	157.2	$	364.0	$	841.0	$	0.9	$	1,363.1











TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020	$	157.2	$	414.0	$	974.3	$	0.1	$	1,545.6



Capital Contribution from Parent			425.0						425.0
Net Loss					(2.7)				(2.7)
Other Comprehensive Loss							(0.1)		(0.1)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021	$	157.2	$	839.0	$	971.6	$	0	$	1,967.8











See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

101

Common
Stock Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 $ 56.6
$ 980.9
$ 1,329.1
$ (13.8 ) $ 2,352.8

Common Stock Dividends

(20.0 )
(20.0 )
Net Income

98.9

98.9
Other Comprehensive Income

0.4
0.4
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 $ 56.6
$ 980.9
$ 1,408.0
$ (13.4 ) $ 2,432.1

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019 $ 56.6
$ 980.9
$ 1,518.5
$ (11.6 ) $ 2,544.4

Common Stock Dividends (21.3 ) (21.3 )
ASU 2016-13 Adoption 0.4
0.4
Net Income 92.3
92.3
Other Comprehensive Income 0.4
0.4
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020 $ 56.6
$ 980.9
$ 1,589.9
$ (11.2 ) $ 2,616.2

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~INDIANA MICHIGAN POWER~~PUBLIC SERVICE COMPANY ~~AND SUBSIDIARIES~~OF OKLAHOMA

CONDENSED ~~CONSOLIDATED~~ BALANCE SHEETS

ASSETS

March 31, ~~2020~~2021 and December 31, ~~2019~~2020

(in millions)

(Unaudited)


	March 31,		December 31,
	2021		2020
CURRENT ASSETS
Cash and Cash Equivalents	$	2.4	$	2.6

Accounts Receivable:
Customers	37.7		30.8
Affiliated Companies	21.8		15.6
Miscellaneous	0.1		2.0

Total Accounts Receivable	59.6		48.4
Fuel	14.1		17.9
Materials and Supplies	53.3		54.0
Risk Management Assets	5.5		10.3

Accrued Tax Benefits	9.9		10.9
Regulatory Asset for Under-Recovered Fuel Costs	44.8		30.1
Prepayments and Other Current Assets	7.4		7.1
TOTAL CURRENT ASSETS	197.0		181.3

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	1,481.7		1,480.7
Transmission	1,082.0		1,069.9
Distribution	2,896.4		2,853.0
Other Property, Plant and Equipment	411.0		393.3
Construction Work in Progress	98.2		128.7
Total Property, Plant and Equipment	5,969.3		5,925.6
Accumulated Depreciation and Amortization	1,626.0		1,605.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	4,343.3		4,320.0

OTHER NONCURRENT ASSETS
Regulatory Assets	1,067.6		375.0

Employee Benefits and Pension Assets	65.9		65.8
Operating Lease Assets	42.4		42.6
Deferred Charges and Other Noncurrent Assets	39.6		6.0
TOTAL OTHER NONCURRENT ASSETS	1,215.5		489.4

TOTAL ASSETS	$	5,755.8	$	4,990.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

102

March 31, December 31,
2020 2019
CURRENT ASSETS
Cash and Cash Equivalents $ 1.8
$ 2.0
Advances to Affiliates 13.3
13.2
Accounts Receivable:
Customers 47.5
53.6
Affiliated Companies 51.1
53.7
Accrued Unbilled Revenues 1.8
2.5
Miscellaneous 1.3
0.3
Allowance for Uncollectible Accounts (0.3 ) (0.6 )
Total Accounts Receivable 101.4
109.5
Fuel 71.7
56.2
Materials and Supplies 171.1
171.3
Risk Management Assets 6.7
9.8
Regulatory Asset for Under-Recovered Fuel Costs 1.2
3.0
Accrued Reimbursement of Spent Nuclear Fuel Costs 8.4
24.0
Prepayments and Other Current Assets 16.4
14.0
TOTAL CURRENT ASSETS 392.0
403.0

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 5,114.0
5,099.7
Transmission 1,647.5
1,641.8
Distribution 2,474.8
2,437.6
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 617.4
632.6
Construction Work in Progress 420.1
382.3
Total Property, Plant and Equipment 10,273.8
10,194.0
Accumulated Depreciation, Depletion and Amortization 3,356.3
3,294.3
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 6,917.5
6,899.7

OTHER NONCURRENT ASSETS
Regulatory Assets 459.0
482.1
Spent Nuclear Fuel and Decommissioning Trusts 2,679.2
2,975.7
Long-term Risk Management Assets 0.1
0.1
Operating Lease Assets 273.6
294.9
Deferred Charges and Other Noncurrent Assets 184.0
181.9
TOTAL OTHER NONCURRENT ASSETS 3,595.9
3,934.7

TOTAL ASSETS $ 10,905.4
$ 11,237.4

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~INDIANA MICHIGAN POWER~~PUBLIC SERVICE COMPANY ~~AND SUBSIDIARIES~~OF OKLAHOMA

CONDENSED ~~CONSOLIDATED~~ BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, ~~2020~~2021 and December 31, ~~2019~~

~~(dollars in millions)~~2020

(Unaudited)


	March 31,		December 31,
	2021		2020
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	245.7	$	155.4
Accounts Payable:
General	107.4		107.0
Affiliated Companies	49.6		43.4
Long-term Debt Due Within One Year – Nonaffiliated	0.5		0.5

Customer Deposits	53.6		54.8
Accrued Taxes	48.2		26.8

Obligations Under Operating Leases	6.6		6.5


Other Current Liabilities	57.6		84.2
TOTAL CURRENT LIABILITIES	569.2		478.6

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	1,623.3		1,373.3

Deferred Income Taxes	693.7		688.5
Regulatory Liabilities and Deferred Investment Tax Credits	799.7		802.2
Asset Retirement Obligations	46.0		45.7

Obligations Under Operating Leases	35.8		36.2
Deferred Credits and Other Noncurrent Liabilities	20.3		20.6
TOTAL NONCURRENT LIABILITIES	3,218.8		2,966.5

TOTAL LIABILITIES	3,788.0		3,445.1

Rate Matters (Note 4)	0		0
Commitments and Contingencies (Note 5)	0		0

COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
Authorized – 11,000,000 Shares
Issued – 10,482,000 Shares
Outstanding – 9,013,000 Shares	157.2		157.2
Paid-in Capital	839.0		414.0
Retained Earnings	971.6		974.3
Accumulated Other Comprehensive Income (Loss)	0		0.1
TOTAL COMMON SHAREHOLDER’S EQUITY	1,967.8		1,545.6

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	5,755.8	$	4,990.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

103

March 31, December 31,
2020 2019
CURRENT LIABILITIES
Advances from Affiliates $ 103.7
$ 114.4
Accounts Payable:
General 131.5
169.4
Affiliated Companies 71.0
68.4
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2020 and December 31, 2019 Amounts Include $80.0 and $86.1, Respectively, Related to DCC Fuel) 133.6
139.7
Risk Management Liabilities 1.7
0.5
Customer Deposits 38.8
39.4
Accrued Taxes 137.4
112.4
Accrued Interest 20.3
36.2
Obligations Under Operating Leases 85.3
87.3
Regulatory Liability for Over-Recovered Fuel Costs 26.7
6.1
Other Current Liabilities 70.8
109.6
TOTAL CURRENT LIABILITIES 820.8
883.4

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated 2,894.4
2,910.5
Long-term Risk Management Liabilities 0.1
—
Deferred Income Taxes 984.3
979.7
Regulatory Liabilities and Deferred Investment Tax Credits 1,550.4
1,891.4
Asset Retirement Obligations 1,766.0
1,748.6
Obligations Under Operating Leases 209.0
211.6
Deferred Credits and Other Noncurrent Liabilities 64.2
67.8
TOTAL NONCURRENT LIABILITIES 7,468.4
7,809.6

TOTAL LIABILITIES 8,289.2
8,693.0

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 2,500,000 Shares
Outstanding – 1,400,000 Shares 56.6
56.6
Paid-in Capital 980.9
980.9
Retained Earnings 1,589.9
1,518.5
Accumulated Other Comprehensive Income (Loss) (11.2 ) (11.6 )
TOTAL COMMON SHAREHOLDER’S EQUITY 2,616.2
2,544.4

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 10,905.4
$ 11,237.4

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~INDIANA MICHIGAN POWER~~PUBLIC SERVICE COMPANY ~~AND SUBSIDIARIES~~OF OKLAHOMA

CONDENSED ~~CONSOLIDATED~~ STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2021		2020
OPERATING ACTIVITIES
Net Loss	$	(2.7)	$	(10.3)
Adjustments to Reconcile Net Loss to Net Cash Flows Used for Operating Activities:
Depreciation and Amortization	49.9		44.7
Deferred Income Taxes	(0.8)		(5.3)

Allowance for Equity Funds Used During Construction	(0.4)		(1.0)
Mark-to-Market of Risk Management Contracts	4.8		9.5

Property Taxes	(32.8)		(29.8)
Deferred Fuel Over/Under-Recovery, Net	(703.5)		4.1

Change in Other Noncurrent Assets	(7.3)		(0.1)
Change in Other Noncurrent Liabilities	1.5		4.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(11.2)		0.9
Fuel, Materials and Supplies	4.5		(8.5)
Accounts Payable	15.2		(39.1)
Accrued Taxes, Net	22.4		25.1
Other Current Assets	(0.3)		(1.7)
Other Current Liabilities	(24.7)		(7.2)
Net Cash Flows Used for Operating Activities	(685.4)		(14.5)

INVESTING ACTIVITIES
Construction Expenditures	(79.9)		(96.5)
Change in Advances to Affiliates, Net	0		38.8
Other Investing Activities	0.5		1.6
Net Cash Flows Used for Investing Activities	(79.4)		(56.1)

FINANCING ACTIVITIES
Capital Contributions from Parent	425.0		0
Issuance of Long-term Debt – Nonaffiliated	500.0		0
Change in Advances from Affiliates, Net	90.3		70.9
Retirement of Long-term Debt – Nonaffiliated	(250.1)		(0.1)

Principal Payments for Finance Lease Obligations	(0.9)		(0.8)

Other Financing Activities	0.3		0.2
Net Cash Flows from Financing Activities	764.6		70.2

Net Decrease in Cash and Cash Equivalents	(0.2)		(0.4)
Cash and Cash Equivalents at Beginning of Period	2.6		1.5
Cash and Cash Equivalents at End of Period	$	2.4	$	1.1

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	16.9	$	16.7

Noncash Acquisitions Under Finance Leases	1.0		0.9
Construction Expenditures Included in Current Liabilities as of March 31,	22.2		30.8

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

104

Three Months Ended March 31,
2020 2019
OPERATING ACTIVITIES

Net Income $ 92.3
$ 98.9
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

Depreciation and Amortization 93.9
86.2
Deferred Income Taxes (16.3 ) (13.9 )
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net 15.2
(14.8 )
Allowance for Equity Funds Used During Construction (2.0 ) (6.2 )
Mark-to-Market of Risk Management Contracts 4.4
4.7
Amortization of Nuclear Fuel 23.4
25.1
Deferred Fuel Over/Under-Recovery, Net 22.5
(5.2 )
Change in Other Noncurrent Assets 14.4
13.5
Change in Other Noncurrent Liabilities 10.0
5.2
Changes in Certain Components of Working Capital:

Accounts Receivable, Net 8.6
16.0
Fuel, Materials and Supplies (16.2 ) 6.6
Accounts Payable (21.6 ) (3.1 )
Accrued Taxes, Net 25.0
25.6
Other Current Assets 18.2
1.4
Other Current Liabilities (62.7 ) (35.2 )
Net Cash Flows from Operating Activities 209.1
204.8

INVESTING ACTIVITIES

Construction Expenditures (141.4 ) (149.3 )
Change in Advances to Affiliates, Net (0.1 ) (0.1 )
Purchases of Investment Securities (626.0 ) (130.3 )
Sales of Investment Securities 612.4
111.9
Acquisitions of Nuclear Fuel (1.3 ) (32.4 )
Other Investing Activities 4.2
8.6
Net Cash Flows Used for Investing Activities (152.2 ) (191.6 )

FINANCING ACTIVITIES

Change in Advances from Affiliates, Net (10.7 ) 33.6
Retirement of Long-term Debt – Nonaffiliated (23.7 ) (26.5 )
Principal Payments for Finance Lease Obligations (1.5 ) (1.2 )
Dividends Paid on Common Stock (21.3 ) (20.0 )
Other Financing Activities 0.1
0.2
Net Cash Flows Used for Financing Activities (57.1 ) (13.9 )

Net Decrease in Cash and Cash Equivalents (0.2 ) (0.7 )
Cash and Cash Equivalents at Beginning of Period 2.0
2.4
Cash and Cash Equivalents at End of Period $ 1.8
$ 1.7

SUPPLEMENTARY INFORMATION

Cash Paid for Interest, Net of Capitalized Amounts $ 44.3
$ 43.3
Net Cash Paid (Received) for Income Taxes —
(3.3 )
Noncash Acquisitions Under Finance Leases 1.4
1.7
Construction Expenditures Included in Current Liabilities as of March 31, 67.8
80.0
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31, —
1.0
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 1.3
7.9

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~
~~110~~.

~~OHIO~~SOUTHWESTERN ELECTRIC POWER COMPANY ~~AND SUBSIDIARIES~~CONSOLIDATED

105

~~OHIO~~SOUTHWESTERN ELECTRIC POWER COMPANY ~~AND SUBSIDIARIES~~CONSOLIDATED

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales



	Three Months Ended March 31,
	2021	2020
	(in millions of KWhs)
Retail:
Residential	1,700	1,406
Commercial	1,209	1,228
Industrial	971	1,242
Miscellaneous	18	20
Total Retail	3,898	3,896

Wholesale	1,541	1,326

Total KWhs	5,439	5,222

Three Months Ended March 31,
2020 2019
(in millions of KWhs)
Retail:

Residential 3,834
4,123
Commercial 3,516
3,527
Industrial 3,543
3,623
Miscellaneous 30
31
Total Retail (a) 10,923
11,304

Wholesale (b) 390
638

Total KWhs 11,313
11,942


~~(a)~~	~~Represents energy delivered to distribution customers.~~


~~(b)~~	~~Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.~~

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2021	2020
	(in degree days)
Actual – Heating (a)	763	497
Normal – Heating (b)	697	698

Actual – Cooling (c)	45	69
Normal – Cooling (b)	40	39

(a)Heating degree days are calculated on a 55 degree temperature base.

(b)Normal Heating/Cooling represents the thirty-year average of degree days.

(c)Cooling degree days are calculated on a 65 degree temperature base.

106

Three Months Ended March 31,
2020 2019
(in degree days)
Actual – Heating (a) 1,473
1,892
Normal – Heating (b) 1,898
1,877

Actual – Cooling (c) 3
1
Normal – Cooling (b) 3
3


~~(a)~~	~~Heating degree days are calculated on a 55 degree temperature base.~~


~~(b)~~	~~Normal Heating/Cooling represents the thirty-year average of degree days.~~


~~(c)~~	~~Cooling degree days are calculated on a 65 degree temperature base.~~

First Quarter of ~~2020~~2021 Compared to First Quarter of ~~2019~~2020

Reconciliation of First Quarter of 2019 to First Quarter of 2020
Net Income
(in millions)

First Quarter of 2019 $ 128.0

Changes in Gross Margin:
Retail Margins (93.7 )
Margins from Off-system Sales 2.3
Transmission Revenues 0.6
Other Revenues 5.5
Total Change in Gross Margin (85.3 )

Changes in Expenses and Other:
Other Operation and Maintenance 40.5
Depreciation and Amortization (7.2 )
Taxes Other Than Income Taxes (3.1 )
Interest Income (0.6 )
Carrying Costs Income 0.2
Allowance for Equity Funds Used During Construction (3.3 )
Non-Service Cost Components of Net Periodic Benefit Cost 0.1
Interest Expense (4.3 )
Total Change in Expenses and Other 22.3

Income Tax Expense 10.1

First Quarter of 2020 $ 75.1

~~The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:~~


•									~~Retail Margins~~ ~~decreased $94 million primarily due~~Reconciliation of First Quarter of 2020 to ~~the following:~~First Quarter of 2021

~~A $58 million decrease due to a reversal of a regulatory provision in the first quarter of 2019.~~

~~A $39 million net decrease in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset in Other Operation and Maintenance expenses below.~~

~~A $13 million decrease in Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below.~~

~~A $7 million net decrease in margin for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.~~

~~A $5 million decrease due to the OVEC PPA rider which was replaced by the Legacy Generation Resource Rider (LGRR). This decrease was offset in Margins from Off-system Sales and Other Revenues below.~~

~~A $3 million decrease in revenues associated with a vegetation management rider. This decrease was offset in Other Operation and Maintenance expenses below.~~

~~These decreases were partially offset by:~~

~~A $17 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.~~

~~A $7 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.~~

~~A $7 million increase in revenues associated with the Universal Service Fund (USF). This increase was offset in Other Operation and Maintenance expenses below.~~

~~A $3 million increase in Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset in Other Operation and Maintenance expenses below.~~

Earnings Attributable to SWEPCo Common Shareholder
(in millions)

•First Quarter of 2020	~~Other Revenues~~$	15.1
~~increased~~ ~~$6 million~~	~~primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset~~
Changes in Gross Margin:
Retail Margins ~~above.~~(a)	40.2

~~Expenses and Other and Income Tax Expense changed between years as follows:~~

Margins from Off-system Sales						20.2
Transmission Revenues						2.2

•Total Change in Gross Margin						62.6

Changes in Expenses and Other:
Other Operation and Maintenance						~~expenses decreased $41 million primarily due to the following:~~1.7

~~A $40 million decrease in recoverable PJM expenses. This decrease was offset in Gross Margin above.~~

~~A $6 million decrease in PJM expenses primarily related to the annual formula rate true-up.~~

~~A $4 million decrease in recoverable distribution expenses related to vegetation management. This decrease was partially offset in Retail Margins above.~~

~~These decreases were partially offset by:~~

A $7 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.


•			Depreciation and Amortization				~~expenses~~(2.3)~~increased~~ ~~$7 million primarily due to the following:~~

~~A $5 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.~~

~~A $5 million increase due to lower deferred equity amortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in the second quarter of 2019.~~

~~A $5 million increase in recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.~~

~~These increases were partially offset by:~~

~~A $10 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.~~


•			Taxes Other Than Income Taxes				~~increased~~(4.7) ~~$3 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.~~


•Interest Income						0.4
Allowance for Equity Funds Used During Construction ~~decreased $3 million primarily due to adjustments that resulted from 2019 FERC audit findings and decreased projects.~~

			0.7
•	~~Interest Expense~~ ~~increased $4 million primarily due to higher long-term debt balances.~~


•	~~Income Tax Expense~~ decreased $10 million due to a decrease in pretax book income partially offset by a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset in Retail Margins above.

~~OHIO POWER COMPANY AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATED STATEMENTS OF INCOME~~

~~For the Three Months Ended March 31, 2020 and 2019~~

~~(in millions)~~

~~(Unaudited)~~

Three Months Ended March 31,
2020 2019
REVENUES
Electricity, Transmission and Distribution $ 679.2
$ 826.5
Sales to AEP Affiliates 8.4
7.5
Other Revenues 2.7
2.8
TOTAL REVENUES 690.3
836.8

EXPENSES

Purchased Electricity for Resale 149.1
174.2
Purchased Electricity from AEP Affiliates 42.4
46.1
Amortization of Generation Deferrals —
32.4
Other Operation 177.3
216.9
Maintenance 31.6
32.5
Depreciation and Amortization 70.5
63.3
Taxes Other Than Income Taxes 112.0
108.9
TOTAL EXPENSES 582.9
674.3

OPERATING INCOME 107.4
162.5

Other Income (Expense):

Interest Income 0.2
0.8
Carrying Costs Income 0.4
0.2
Allowance for Equity Funds Used During Construction 1.9
5.2
Non-Service Cost Components of Net Periodic Benefit Cost 3.8
3.7
Interest Expense (28.9 ) (24.6 )

INCOME BEFORE INCOME TAX EXPENSE 84.8
147.8

Income Tax Expense 9.7
19.8

NET INCOME $ 75.1
$ 128.0




~~The common stock of OPCo is wholly-owned by Parent.~~
Interest Expense				0.8
~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~OHIO POWER COMPANY AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)~~

~~For the Three Months Ended March 31, 2020 and 2019~~

~~(in millions)~~

~~(Unaudited)~~

Three Months Ended March 31,
2020 2019
Net Income $ 75.1
$ 128.0

OTHER COMPREHENSIVE LOSS, NET OF TAXES

Cash Flow Hedges, Net of Tax of $0 and $(0.1) in 2020 and 2019, Respectively —
(0.3 )

TOTAL COMPREHENSIVE INCOME $ 75.1
$ 127.7


Total Change in Expenses and Other						(3.4)
~~See Condensed Notes to Condensed Financial Statements~~
Income Tax Expense						(11.8)
Equity Earnings of ~~Registrants beginning on page~~ Unconsolidated Subsidiary~~110~~						.(0.1)

~~OHIO POWER COMPANY AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN~~

~~COMMON SHAREHOLDER’S EQUITY~~

~~For the Three Months Ended March 31, 2020 and 2019~~

~~(in millions)~~

~~(Unaudited)~~

Common
Stock Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 $ 321.2
$ 838.8
$ 1,136.4
$ 1.0
$ 2,297.4

Common Stock Dividends (25.0 ) (25.0 )
Net Income 128.0
128.0
Other Comprehensive Loss (0.3 ) (0.3 )
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 $ 321.2
$ 838.8
$ 1,239.4
$ 0.7
$ 2,400.1

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019 $ 321.2
$ 838.8
$ 1,348.5
$ —
$ 2,508.5

Common Stock Dividends (21.9 ) (21.9 )
ASU 2016-13 Adoption 0.3
0.3
Net Income 75.1
75.1
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020 $ 321.2
$ 838.8
$ 1,402.0
$ —
$ 2,562.0




~~See Condensed Notes to Condensed Financial Statements~~First Quarter of ~~Registrants beginning on page~~ 2021~~110~~	.$	62.4

~~OHIO POWER COMPANY AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~ASSETS~~

~~March 31, 2020~~(a)Includes firm wholesale sales to municipals and ~~December 31, 2019~~cooperatives.

~~(in millions)~~

~~(Unaudited)~~

March 31, December 31,
2020 2019
CURRENT ASSETS
Cash and Cash Equivalents $ 3.1
$ 3.7
Accounts Receivable:
Customers 42.9
53.0
Affiliated Companies 73.1
59.3
Accrued Unbilled Revenues 34.2
20.3
Miscellaneous 3.8
0.5
Allowance for Uncollectible Accounts (0.4 ) (0.7 )
Total Accounts Receivable 153.6
132.4
Materials and Supplies 58.3
52.3
Renewable Energy Credits 26.9
30.9
Prepayments and Other Current Assets 23.7
19.2
TOTAL CURRENT ASSETS 265.6
238.5

PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission 2,713.0
2,686.3
Distribution 5,404.5
5,323.5
Other Property, Plant and Equipment 797.2
765.8
Construction Work in Progress 412.5
394.4
Total Property, Plant and Equipment 9,327.2
9,170.0
Accumulated Depreciation and Amortization 2,292.8
2,263.0
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 7,034.4
6,907.0

OTHER NONCURRENT ASSETS
Regulatory Assets 396.4
351.8
Deferred Charges and Other Noncurrent Assets 485.6
546.3
TOTAL OTHER NONCURRENT ASSETS 882.0
898.1

TOTAL ASSETS $ 8,182.0
$ 8,043.6



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~OHIO POWER COMPANY AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~LIABILITIES AND COMMON SHAREHOLDER’S EQUITY~~

~~March 31, 2020 and December 31, 2019~~

~~(dollars in millions)~~

~~(Unaudited)~~

March 31, December 31,
2020 2019
CURRENT LIABILITIES
Advances from Affiliates $ 29.4
$ 131.0
Accounts Payable:

General 220.3
233.7
Affiliated Companies 109.0
103.6
Long-term Debt Due Within One Year – Nonaffiliated 0.1
0.1
Risk Management Liabilities 8.7
7.3
Customer Deposits 74.1
70.6
Accrued Taxes 449.2
587.9
Obligations Under Operating Leases 13.0
12.5
Other Current Liabilities 139.5
151.2
TOTAL CURRENT LIABILITIES 1,043.3
1,297.9

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated 2,429.0
2,081.9
Long-term Risk Management Liabilities 112.2
96.3
Deferred Income Taxes 871.0
849.4
Regulatory Liabilities and Deferred Investment Tax Credits 1,040.6
1,090.9
Obligations Under Operating Leases 79.8
76.0
Deferred Credits and Other Noncurrent Liabilities 44.1
42.7
TOTAL NONCURRENT LIABILITIES 4,576.7
4,237.2

TOTAL LIABILITIES 5,620.0
5,535.1

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 40,000,000 Shares

Outstanding – 27,952,473 Shares 321.2
321.2
Paid-in Capital 838.8
838.8
Retained Earnings 1,402.0
1,348.5
TOTAL COMMON SHAREHOLDER’S EQUITY 2,562.0
2,508.5

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 8,182.0
$ 8,043.6



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~OHIO POWER COMPANY AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~For the Three Months Ended March 31, 2020 and 2019~~

~~(in millions)~~

~~(Unaudited)~~

Three Months Ended March 31,
2020 2019
OPERATING ACTIVITIES

Net Income $ 75.1
$ 128.0
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

Depreciation and Amortization 70.5
63.3
Amortization of Generation Deferrals —
32.4
Deferred Income Taxes 12.9
10.1
Allowance for Equity Funds Used During Construction (1.9 ) (5.2 )
Mark-to-Market of Risk Management Contracts 17.3
6.7
Property Taxes 74.4
66.0
Refund of Global Settlement —
(4.1 )
Reversal of Regulatory Provision —
(56.2 )
Change in Other Noncurrent Assets (61.5 ) (7.5 )
Change in Other Noncurrent Liabilities (36.4 ) 17.6
Changes in Certain Components of Working Capital:

Accounts Receivable, Net (19.9 ) 31.7
Materials and Supplies (10.2 ) (3.4 )
Accounts Payable 35.5
(23.9 )
Accrued Taxes, Net (141.9 ) (114.4 )
Other Current Assets (2.0 ) (7.7 )
Other Current Liabilities (8.4 ) (16.2 )
Net Cash Flows from Operating Activities 3.5
117.2

INVESTING ACTIVITIES

Construction Expenditures (232.8 ) (198.5 )
Other Investing Activities 5.9
3.7
Net Cash Flows Used for Investing Activities (226.9 ) (194.8 )

FINANCING ACTIVITIES

Issuance of Long-term Debt – Nonaffiliated 347.1
—
Change in Advances from Affiliates, Net (101.6 ) 113.5
Retirement of Long-term Debt – Nonaffiliated —
(23.4 )
Principal Payments for Finance Lease Obligations (1.2 ) (0.7 )
Dividends Paid on Common Stock (21.9 ) (25.0 )
Other Financing Activities 0.4
0.5
Net Cash Flows from Financing Activities 222.8
64.9

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (0.6 ) (12.7 )
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 3.7
32.5
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $ 3.1
$ 19.8

SUPPLEMENTARY INFORMATION

Cash Paid for Interest, Net of Capitalized Amounts $ 16.7
$ 17.0
Net Cash Paid (Received) for Income Taxes —
(0.2 )
Noncash Acquisitions Under Finance Leases 4.3
3.2
Construction Expenditures Included in Current Liabilities as of March 31, 72.9
72.8



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~PUBLIC SERVICE COMPANY OF OKLAHOMA~~

~~MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS~~

~~RESULTS OF OPERATIONS~~

~~KWh Sales/Degree Days~~

~~Summary of KWh Energy Sales~~

Three Months Ended March 31,
2020 2019
(in millions of KWhs)
Retail:

Residential 1,362
1,520
Commercial 1,055
1,089
Industrial 1,437
1,433
Miscellaneous 272
274
Total Retail 4,126
4,316

Wholesale 53
245

Total KWhs 4,179
4,561

~~Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.~~

~~Summary of Heating and Cooling Degree Days~~

Three Months Ended March 31,
2020 2019
(in degree days)
Actual – Heating (a) 799
1,171
Normal – Heating (b) 1,034
1,032

Actual – Cooling (c) 33
3
Normal – Cooling (b) 17
17


~~(a)~~	~~Heating degree days are calculated on a 55 degree temperature base.~~


~~(b)~~	~~Normal Heating/Cooling represents the thirty-year average of degree days.~~


~~(c)~~	~~Cooling degree days are calculated on a 65 degree temperature base.~~

~~First Quarter of 2020 Compared to First Quarter of 2019~~

Reconciliation of First Quarter of 2019 to First Quarter of 2020
Net Income (Loss)
(in millions)

First Quarter of 2019 $ 6.2

Changes in Gross Margin:
Retail Margins (a) —
Margins from Off-system Sales (0.2 )
Transmission Revenues (0.5 )
Other Revenues (1.2 )
Total Change in Gross Margin (1.9 )

Changes in Expenses and Other:
Other Operation and Maintenance (15.5 )
Depreciation and Amortization (1.2 )
Taxes Other Than Income Taxes 0.1
Interest Income 0.1
Allowance for Equity Funds Used During Construction 0.9
Interest Expense 1.1
Total Change in Expenses and Other (14.5 )

Income Tax Expense (0.1 )

First Quarter of 2020 $ (10.3 )


~~(a)~~	~~Includes firm wholesale sales to municipals and cooperatives.~~

The major components of the ~~decrease~~increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:


•	~~Retail Margins~~ ~~were consistent with the prior year due to the following:~~

~~An $11~~•Retail Margins increased $40 million ~~increase~~primarily due to ~~new base rates implemented in April 2019.~~the following:

~~This increase was partially offset by:~~

•A ~~$7 million decrease in revenue from rate riders. This decrease was partially offset in other expense items below.~~

~~A $3 million decrease in weather-related usage due to a 32% decrease in heating degree days.~~

~~Expenses and Other changed between years as follows:~~


•	~~Other Operation and Maintenance~~ ~~expenses increased $16 million primarily due the following:~~

~~A $6~~$17 million increase in ~~transmission expenses~~municipal and cooperative revenues primarily due to ~~increased SPP transmission services.~~the February 2021 severe winter weather event.

•A $5$10 million increase ~~in distribution expenses primarily due to an increase in vegetation management expenses.~~

~~A $1 million increase in Energy Efficiency program costs. This increase was offset in Retail Margins above.~~

~~PUBLIC SERVICE COMPANY OF OKLAHOMA~~

~~CONDENSED STATEMENTS OF OPERATIONS~~

~~For the Three Months Ended March 31, 2020 and 2019~~

~~(in millions)~~

~~(Unaudited)~~

Three Months Ended March 31,
2020 2019
REVENUES
Electric Generation, Transmission and Distribution $ 295.4
$ 329.2
Sales to AEP Affiliates 1.1
1.6
Other Revenues 0.8
2.0
TOTAL REVENUES 297.3
332.8

EXPENSES

Fuel and Other Consumables Used for Electric Generation 16.9
38.0
Purchased Electricity for Resale 110.4
122.9
Other Operation 87.2
73.6
Maintenance 24.4
22.5
Depreciation and Amortization 44.7
43.5
Taxes Other Than Income Taxes 11.3
11.4
TOTAL EXPENSES 294.9
311.9

OPERATING INCOME 2.4
20.9

Other Income (Expense):

Interest Income 0.1
—
Allowance for Equity Funds Used During Construction 1.0
0.1
Non-Service Cost Components of Net Periodic Benefit Cost 2.1
2.1
Interest Expense (15.8 ) (16.9 )

INCOME (LOSS) BEFORE INCOME TAX EXPENSE (10.2 ) 6.2

Income Tax Expense 0.1
—

NET INCOME (LOSS) $ (10.3 ) $ 6.2



~~The common stock of PSO is wholly-owned by Parent.~~

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~PUBLIC SERVICE COMPANY OF OKLAHOMA~~

~~CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)~~

~~For the Three Months Ended March 31, 2020 and 2019~~

~~(in millions)~~

~~(Unaudited)~~

Three Months Ended March 31,
2020 2019
Net Income (Loss) $ (10.3 ) $ 6.2

OTHER COMPREHENSIVE LOSS, NET OF TAXES

Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2020 and 2019, Respectively (0.2 ) (0.2 )

TOTAL COMPREHENSIVE INCOME (LOSS) $ (10.5 ) $ 6.0



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~PUBLIC SERVICE COMPANY OF OKLAHOMA~~

~~CONDENSED STATEMENTS OF CHANGES IN~~

~~COMMON SHAREHOLDER’S EQUITY~~

~~For the Three Months Ended March 31, 2020 and 2019~~

~~(in millions)~~

~~(Unaudited)~~

Common
Stock Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 $ 157.2
$ 364.0
$ 724.7
$ 2.1
$ 1,248.0

Common Stock Dividends (11.3 ) (11.3 )
Net Income 6.2
6.2
Other Comprehensive Loss (0.2 ) (0.2 )
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 $ 157.2
$ 364.0
$ 719.6
$ 1.9
$ 1,242.7

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019 $ 157.2
$ 364.0
$ 851.0
$ 1.1
$ 1,373.3

ASU 2016-13 Adoption 0.3
0.3
Net Loss (10.3 ) (10.3 )
Other Comprehensive Loss (0.2 ) (0.2 )
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020 $ 157.2
$ 364.0
$ 841.0
$ 0.9
$ 1,363.1



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~PUBLIC SERVICE COMPANY OF OKLAHOMA~~

~~CONDENSED BALANCE SHEETS~~

~~ASSETS~~

~~March 31, 2020 and December 31, 2019~~

~~(in millions)~~

~~(Unaudited)~~

March 31, December 31,
2020 2019
CURRENT ASSETS
Cash and Cash Equivalents $ 1.1
$ 1.5
Advances to Affiliates —
38.8
Accounts Receivable:
Customers 28.4
28.9
Affiliated Companies 19.9
20.6
Miscellaneous 0.8
0.6
Allowance for Uncollectible Accounts (0.2 ) (0.3 )
Total Accounts Receivable 48.9
49.8
Fuel 19.6
12.2
Materials and Supplies 47.9
46.8
Risk Management Assets 6.4
15.8
Accrued Tax Benefits 5.7
11.3
Prepayments and Other Current Assets 13.4
12.0
TOTAL CURRENT ASSETS 143.0
188.2

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 1,577.2
1,574.6
Transmission 959.5
948.5
Distribution 2,724.3
2,684.8
Other Property, Plant and Equipment 350.3
342.1
Construction Work in Progress 144.9
133.4
Total Property, Plant and Equipment 5,756.2
5,683.4
Accumulated Depreciation and Amortization 1,615.8
1,580.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 4,140.4
4,103.3

OTHER NONCURRENT ASSETS
Regulatory Assets 378.4
375.2
Employee Benefits and Pension Assets 44.2
43.9
Operating Lease Assets 38.0
36.8
Deferred Charges and Other Noncurrent Assets 34.0
4.1
TOTAL OTHER NONCURRENT ASSETS 494.6
460.0

TOTAL ASSETS $ 4,778.0
$ 4,751.5



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~PUBLIC SERVICE COMPANY OF OKLAHOMA~~

~~CONDENSED BALANCE SHEETS~~

~~LIABILITIES AND COMMON SHAREHOLDER’S EQUITY~~

~~March 31, 2020 and December 31, 2019~~

~~(Unaudited)~~

March 31, December 31,
2020 2019
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ 70.9
$ —
Accounts Payable:

General 102.5
134.3
Affiliated Companies 39.8
59.3
Long-term Debt Due Within One Year – Nonaffiliated 263.2
13.2
Risk Management Liabilities 0.1
—
Customer Deposits 59.3
58.9
Accrued Taxes 42.4
22.9
Obligations Under Operating Leases 6.0
5.8
Regulatory Liability for Over-Recovered Fuel Costs 68.0
63.9
Other Current Liabilities 78.6
87.5
TOTAL CURRENT LIABILITIES 730.8
445.8

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated 1,123.1
1,373.0
Deferred Income Taxes 629.6
628.3
Regulatory Liabilities and Deferred Investment Tax Credits 835.0
837.2
Asset Retirement Obligations 45.3
44.5
Obligations Under Operating Leases 32.1
31.0
Deferred Credits and Other Noncurrent Liabilities 19.0
18.4
TOTAL NONCURRENT LIABILITIES 2,684.1
2,932.4

TOTAL LIABILITIES 3,414.9
3,378.2

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
Authorized – 11,000,000 Shares

Issued – 10,482,000 Shares

Outstanding – 9,013,000 Shares 157.2
157.2
Paid-in Capital 364.0
364.0
Retained Earnings 841.0
851.0
Accumulated Other Comprehensive Income (Loss) 0.9
1.1
TOTAL COMMON SHAREHOLDER’S EQUITY 1,363.1
1,373.3

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $ 4,778.0
$ 4,751.5



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~PUBLIC SERVICE COMPANY OF OKLAHOMA~~

~~CONDENSED STATEMENTS OF CASH FLOWS~~

~~For the Three Months Ended March 31, 2020 and 2019~~

~~(in millions)~~

~~(Unaudited)~~

Three Months Ended March 31,
2020 2019
OPERATING ACTIVITIES

Net Income (Loss) $ (10.3 ) $ 6.2
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from (Used for) Operating Activities:

Depreciation and Amortization 44.7
43.5
Deferred Income Taxes (5.3 ) (5.8 )
Allowance for Equity Funds Used During Construction (1.0 ) (0.1 )
Mark-to-Market of Risk Management Contracts 9.5
5.1
Property Taxes (29.8 ) (29.9 )
Deferred Fuel Over/Under-Recovery, Net 4.1
(2.4 )
Change in Other Noncurrent Assets (0.1 ) 8.0
Change in Other Noncurrent Liabilities 4.2
(0.7 )
Changes in Certain Components of Working Capital:

Accounts Receivable, Net 0.9
2.0
Fuel, Materials and Supplies (8.5 ) 3.2
Accounts Payable (39.1 ) (23.3 )
Accrued Taxes, Net 25.1
25.3
Other Current Assets (1.7 ) (3.8 )
Other Current Liabilities (7.2 ) 4.4
Net Cash Flows from (Used for) Operating Activities (14.5 ) 31.7

INVESTING ACTIVITIES

Construction Expenditures (96.5 ) (70.7 )
Change in Advances to Affiliates, Net 38.8
—
Other Investing Activities 1.6
0.4
Net Cash Flows Used for Investing Activities (56.1 ) (70.3 )

FINANCING ACTIVITIES

Issuance of Long-term Debt – Nonaffiliated —
99.9
Change in Advances from Affiliates, Net 70.9
(50.3 )
Retirement of Long-term Debt – Nonaffiliated (0.1 ) (0.1 )
Principal Payments for Finance Lease Obligations (0.8 ) (0.7 )
Dividends Paid on Common Stock —
(11.3 )
Other Financing Activities 0.2
0.6
Net Cash Flows from Financing Activities 70.2
38.1

Net Decrease in Cash and Cash Equivalents (0.4 ) (0.5 )
Cash and Cash Equivalents at Beginning of Period 1.5
2.0
Cash and Cash Equivalents at End of Period $ 1.1
$ 1.5

SUPPLEMENTARY INFORMATION

Cash Paid for Interest, Net of Capitalized Amounts $ 16.7
$ 10.9
Net Cash Paid for Income Taxes —
0.6
Noncash Acquisitions Under Finance Leases 0.9
1.1
Construction Expenditures Included in Current Liabilities as of March 31, 30.8
15.6



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

~~SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED~~

~~MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS~~

~~RESULTS OF OPERATIONS~~

~~KWh Sales/Degree Days~~

~~Summary of KWh Energy Sales~~

Three Months Ended March 31,
2020 2019
(in millions of KWhs)
Retail:

Residential 1,406
1,528
Commercial 1,228
1,273
Industrial 1,242
1,250
Miscellaneous 20
20
Total Retail 3,896
4,071

Wholesale 1,326
1,979

Total KWhs 5,222
6,050

~~Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.~~

~~Summary of Heating and Cooling Degree Days~~

Three Months Ended March 31,
2020 2019
(in degree days)
Actual – Heating (a) 497
708
Normal – Heating (b) 698
698

Actual – Cooling (c) 69
20
Normal – Cooling (b) 39
39


~~(a)~~	~~Heating degree days are calculated on a 55 degree temperature base.~~


~~(b)~~	~~Normal Heating/Cooling represents the thirty-year average of degree days.~~


~~(c)~~	~~Cooling degree days are calculated on a 65 degree temperature base.~~

~~First Quarter of 2020 Compared to First Quarter of 2019~~

Reconciliation of First Quarter of 2019 to First Quarter of 2020
Earnings Attributable to SWEPCo Common Shareholder
(in millions)

First Quarter of 2019 $ 27.8

Changes in Gross Margin:
Retail Margins (a) (4.2 )
Margins from Off-system Sales (1.6 )
Transmission Revenues 4.8
Other Revenues (0.3 )
Total Change in Gross Margin (1.3 )

Changes in Expenses and Other:
Other Operation and Maintenance (12.5 )
Depreciation and Amortization (5.2 )
Interest Income (0.1 )
Allowance for Equity Funds Used During Construction (0.4 )
Interest Expense (0.4 )
Total Change in Expenses and Other (18.6 )

Income Tax Expense 6.9
Equity Earnings of Unconsolidated Subsidiary 0.1
Net Income Attributable to Noncontrolling Interest 0.2

First Quarter of 2020 $ 15.1


~~(a)~~	~~Includes firm wholesale sales to municipals and cooperatives.~~


•	~~Retail Margins~~ ~~decreased $4 million primarily due to the following:~~

~~An $8 million decrease in weather-normalized margins.~~

~~A $5 million decrease~~ in weather-related usage primarily due to a ~~30% decrease~~54% increase in heating degree days.

•A $3$5 million ~~decrease~~increase due to ~~an increase~~a decrease in the return of Excess ADIT benefits to customers. This ~~decrease~~increase was offset in Income Tax Expense ~~(Benefit)~~ below.

~~These decreases were partially offset by:~~

~~An $11~~•Off-system Sales increased $20 million ~~increase~~ primarily due to ~~capital investment rider and base rate revenue increases in Texas, Arkansas and Louisiana.~~Turk Plant merchant sales as a result of the February 2021 severe winter weather event.


•	~~Transmission Revenues~~ ~~increased $5 million primarily due to an increase in SPP transmission services revenue.~~

Expenses and Other and Income Tax Expense ~~(Benefit)~~ changed between years as follows:


•	~~Other Operation and Maintenance~~ •Taxes Other Than Income Taxes ~~expenses~~ increased ~~$13 million primarily due to the following:~~

A $5 million primarily due to increased property taxes resulting from the expiration of the Louisiana Industrial Tax Exemption related to the Stall Plant.

•Income Tax Expense increased $12 million primarily due to an increase in ~~storm-related expenses.~~

~~A $3 million increase in SPP transmission expenses.~~

~~A $2 million increase in employee-related expenses.~~


•	~~Depreciation and Amortization~~pretax book income. expenses increased $5 million primarily due to a higher depreciable base and an increase in Arkansas depreciation rates beginning in January 2020. This increase was partially offset within Retail Margins above.


•	~~Income Tax Expense~~ ~~decreased~~ ~~$7 million primarily due to a decrease in pretax book income and an increase in amortization of excess ADIT. The increase in amortization of excess ADIT was partially offset in Retail Margins above.~~

107

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Three Months Ended March 31,							Three Months Ended March 31,
	2020			2019				2021		2020
REVENUES							REVENUES
Electric Generation, Transmission and Distribution	$	377.6		$	414.3		Electric Generation, Transmission and Distribution	$	607.7	$	377.6
Sales to AEP Affiliates	7.5			6.4			Sales to AEP Affiliates	7.8		7.5

Other Revenues	0.8			0.4			Other Revenues	0.6		0.8
TOTAL REVENUES	385.9			421.1			TOTAL REVENUES	616.1		385.9

EXPENSES							EXPENSES
Fuel and Other Consumables Used for Electric Generation	89.1			133.5
Purchased Electricity for Resale	43.1			32.6
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation							Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	299.8		132.2

Other Operation	92.2			84.6			Other Operation	90.3		92.2
Maintenance	33.8			28.9			Maintenance	34.0		33.8

Depreciation and Amortization	67.3			62.1			Depreciation and Amortization	69.6		67.3
Taxes Other Than Income Taxes	25.3			25.3			Taxes Other Than Income Taxes	30.0		25.3
TOTAL EXPENSES	350.8			367.0			TOTAL EXPENSES	523.7		350.8

OPERATING INCOME	35.1			54.1			OPERATING INCOME	92.4		35.1

Other Income (Expense):							Other Income (Expense):
Interest Income	0.6			0.7			Interest Income	1.0		0.6
Allowance for Equity Funds Used During Construction	1.4			1.8			Allowance for Equity Funds Used During Construction	2.1		1.4
Non-Service Cost Components of Net Periodic Benefit Cost	2.1			2.1			Non-Service Cost Components of Net Periodic Benefit Cost	2.1		2.1

Interest Expense	(30.1		)	(29.7		)	Interest Expense	(29.3)		(30.1)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	9.1			29.0			INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	68.3		9.1

Income Tax Expense (Benefit)	(6.2		)	0.7			Income Tax Expense (Benefit)	5.6		(6.2)
Equity Earnings of Unconsolidated Subsidiary	0.8			0.7			Equity Earnings of Unconsolidated Subsidiary	0.7		0.8

NET INCOME	16.1			29.0			NET INCOME	63.4		16.1

Net Income Attributable to Noncontrolling Interest	1.0			1.2			Net Income Attributable to Noncontrolling Interest	1.0		1.0

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	15.1		$	27.8		EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	62.4	$	15.1

The common stock of SWEPCo is wholly-owned by Parent.							The common stock of SWEPCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.							See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.



~~The common stock of SWEPCo is wholly-owned by Parent.~~

~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~. 108

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)




	Three Months Ended March 31,
	2021		2020
Net Income	$	63.4	$	16.1

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2021 and 2020, Respectively	0.4		0.4
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) in 2021 and 2020, Respectively	(0.4)		(0.4)

TOTAL OTHER COMPREHENSIVE INCOME	0		0

TOTAL COMPREHENSIVE INCOME	63.4		16.1

Total Comprehensive Income Attributable to Noncontrolling Interest	1.0		1.0

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	62.4	$	15.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

109

Three Months Ended March 31,
2020 2019
Net Income $ 16.1
$ 29.0

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES

Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2020 and 2019, Respectively 0.4
0.4
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) in 2020 and 2019, Respectively (0.4 ) (0.3 )

TOTAL OTHER COMPREHENSIVE INCOME —
0.1

TOTAL COMPREHENSIVE INCOME 16.1
29.1

Total Comprehensive Income Attributable to Noncontrolling Interest 1.0
1.2

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $ 15.1
$ 27.9



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)

SWEPCo Common Shareholder
Common
Stock Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Noncontrolling
Interest Total
TOTAL EQUITY – DECEMBER 31, 2018 $ 135.7
$ 676.6
$ 1,508.4
$ (5.4 ) $ 0.3
$ 2,315.6

Common Stock Dividends (18.7 ) (18.7 )
Common Stock Dividends – Nonaffiliated (1.1 ) (1.1 )
Net Income 27.8
1.2
29.0
Other Comprehensive Income 0.1
0.1
TOTAL EQUITY – MARCH 31, 2019 $ 135.7
$ 676.6
$ 1,517.5
$ (5.3 ) $ 0.4
$ 2,324.9

TOTAL EQUITY – DECEMBER 31, 2019 $ 135.7
$ 676.6
$ 1,629.5
$ (1.3 ) $ 0.6
$ 2,441.1

Common Stock Dividends – Nonaffiliated (0.7 ) (0.7 )
ASU 2016-13 Adoption 1.6
1.6
Net Income 15.1
1.0
16.1
TOTAL EQUITY – MARCH 31, 2020 $ 135.7
$ 676.6
$ 1,646.2
$ (1.3 ) $ 0.9
$ 2,458.1


	SWEPCo Common Shareholder
	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interest		Total
TOTAL EQUITY – DECEMBER 31, 2019	$	135.7	$	676.6	$	1,629.5	$	(1.3)	$	0.6	$	2,441.1


Common Stock Dividends – Nonaffiliated									(0.7)		(0.7)
ASU 2016-13 Adoption					1.6						1.6
Net Income					15.1				1.0		16.1

TOTAL EQUITY – MARCH 31, 2020	$	135.7	$	676.6	$	1,646.2	$	(1.3)	$	0.9	$	2,458.1














TOTAL EQUITY – DECEMBER 31, 2020	$	0.1	$	812.2	$	1,811.9	$	1.9	$	1.6	$	2,627.7

Capital Contribution from Parent			100.0								100.0

Common Stock Dividends – Nonaffiliated									(1.0)		(1.0)

Net Income					62.4				1.0		63.4

TOTAL EQUITY – MARCH 31, 2021	$	0.1	$	912.2	$	1,874.3	$	1.9	$	1.6	$	2,790.1





See Condensed Notes to Condensed Financial Statements of Registrants beginning on page ~~110~~114.

110

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, ~~2020~~2021 and December 31, ~~2019~~2020

(in millions)

(Unaudited)


	March 31,		December 31,
	2021		2020
CURRENT ASSETS
Cash and Cash Equivalents (March 31, 2021 and December 31, 2020 Amounts Include $14.7 and $10.1, Respectively, Related to Sabine)	$	18.2	$	13.2
Advances to Affiliates	2.1		2.1
Accounts Receivable:
Customers	119.4		27.1
Affiliated Companies	34.6		25.1
Miscellaneous	16.7		12.7

Total Accounts Receivable	170.7		64.9
Fuel (March 31, 2021 and December 31, 2020 Amounts Include $17.2 and $35.2, Respectively, Related to Sabine)	195.6		191.1
Materials and Supplies (March 31, 2021 and December 31, 2020 Amounts Include $21.8 and $23.3, Respectively, Related to Sabine)	93.0		95.8
Risk Management Assets	1.3		3.2

Accrued Tax Benefits	36.3		29.9
Regulatory Asset for Under-Recovered Fuel Costs	5.8		2.6
Prepayments and Other Current Assets	17.9		25.2
TOTAL CURRENT ASSETS	540.9		428.0

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	4,679.8		4,681.4
Transmission	2,203.3		2,165.7
Distribution	2,403.1		2,382.5
Other Property, Plant and Equipment (March 31, 2021 and December 31, 2020 Amounts Include $223.8 and $223.7, Respectively, Related to Sabine)	803.9		788.8
Construction Work in Progress	232.4		228.3
Total Property, Plant and Equipment	10,322.5		10,246.7
Accumulated Depreciation and Amortization (March 31, 2021 and December 31, 2020 Amounts Include $137.7 and $126.5, Respectively, Related to Sabine)	3,275.2		3,158.5
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	7,047.3		7,088.2

OTHER NONCURRENT ASSETS
Regulatory Assets	988.2		403.1


Deferred Charges and Other Noncurrent Assets	291.3		234.8
TOTAL OTHER NONCURRENT ASSETS	1,279.5		637.9

TOTAL ASSETS	$	8,867.7	$	8,154.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

111

March 31, December 31,
2020 2019
CURRENT ASSETS
Cash and Cash Equivalents $ 1.4
$ 1.6
Advances to Affiliates 2.1
2.1
Accounts Receivable:
Customers 25.6
29.0
Affiliated Companies 24.4
34.5
Miscellaneous 14.3
13.5
Allowance for Uncollectible Accounts (0.3 ) (1.7 )
Total Accounts Receivable 64.0
75.3
Fuel
(March 31, 2020 and December 31, 2019 Amounts Include $42 and $47, Respectively, Related to Sabine) 147.9
140.1
Materials and Supplies
(March 31, 2020 and December 31, 2019 Amounts Include $23.3 and $23.1, Respectively, Related to Sabine) 93.8
94.0
Risk Management Assets 2.6
6.4
Regulatory Asset for Under-Recovered Fuel Costs —
4.9
Prepayments and Other Current Assets 34.3
29.7
TOTAL CURRENT ASSETS 346.1
354.1

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 4,703.0
4,691.4
Transmission 2,061.6
2,056.5
Distribution 2,300.8
2,270.7
Other Property, Plant and Equipment
(March 31, 2020 and December 31, 2019 Amounts Include $213.5 and $212.3, Respectively, Related to Sabine) 767.2
733.4
Construction Work in Progress 232.7
216.9
Total Property, Plant and Equipment 10,065.3
9,968.9
Accumulated Depreciation and Amortization
(March 31, 2020 and December 31, 2019 Amounts Include $112 and $107.5, Respectively, Related to Sabine) 2,918.7
2,873.7
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 7,146.6
7,095.2

OTHER NONCURRENT ASSETS
Regulatory Assets 236.6
222.4
Deferred Charges and Other Noncurrent Assets 214.8
160.5
TOTAL OTHER NONCURRENT ASSETS 451.4
382.9

TOTAL ASSETS $ 7,944.1
$ 7,832.2



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

March 31, ~~2020~~2021 and December 31, ~~2019~~2020

(Unaudited)


	March 31,		December 31,
	2021		2020
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	86.9	$	124.6
Accounts Payable:
General	219.7		135.9
Affiliated Companies	51.2		43.0
Short-term Debt – Nonaffiliated	5.0		35.0
Long-term Debt Due Within One Year – Nonaffiliated	381.2		106.2
Risk Management Liabilities	0		0.7
Customer Deposits	60.3		61.3
Accrued Taxes	121.3		41.0
Accrued Interest	22.3		34.6

Obligations Under Operating Leases	8.0		7.9

Other Current Liabilities	127.7		173.4
TOTAL CURRENT LIABILITIES	1,083.6		763.6

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,750.2		2,530.2
Long-term Risk Management Liabilities	0.9		1.0
Deferred Income Taxes	1,017.4		1,017.6
Regulatory Liabilities and Deferred Investment Tax Credits	878.5		863.4
Asset Retirement Obligations	191.9		193.7
Employee Benefits and Pension Obligations	21.6		18.6

Obligations Under Operating Leases	44.3		44.1
Deferred Credits and Other Noncurrent Liabilities	89.2		94.2
TOTAL NONCURRENT LIABILITIES	4,994.0		4,762.8

TOTAL LIABILITIES	6,077.6		5,526.4

Rate Matters (Note 4)	0		0
Commitments and Contingencies (Note 5)	0		0

EQUITY
Common Stock – Par Value – $18 Per Share:
Authorized – 3,680 Shares
Outstanding – 3,680 Shares	0.1		0.1
Paid-in Capital	912.2		812.2
Retained Earnings	1,874.3		1,811.9
Accumulated Other Comprehensive Income (Loss)	1.9		1.9
TOTAL COMMON SHAREHOLDER’S EQUITY	2,788.5		2,626.1

Noncontrolling Interest	1.6		1.6

TOTAL EQUITY	2,790.1		2,627.7

TOTAL LIABILITIES AND EQUITY	$	8,867.7	$	8,154.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

112

March 31, December 31,
2020 2019
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ 148.1
$ 59.9
Accounts Payable:
General 102.5
138.0
Affiliated Companies 37.3
53.6
Short-term Debt – Nonaffiliated 30.5
18.3
Long-term Debt Due Within One Year – Nonaffiliated 121.2
121.2
Risk Management Liabilities 2.2
1.9
Customer Deposits 65.1
65.0
Accrued Taxes 93.0
41.8
Accrued Interest 21.9
34.6
Obligations Under Operating Leases 7.1
6.5
Regulatory Liability for Over-Recovered Fuel Costs 29.7
13.6
Other Current Liabilities 87.8
120.3
TOTAL CURRENT LIABILITIES 746.4
674.7

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated 2,533.2
2,534.4
Long-term Risk Management Liabilities 2.9
3.1
Deferred Income Taxes 944.4
940.9
Regulatory Liabilities and Deferred Investment Tax Credits 885.8
892.3
Asset Retirement Obligations 219.7
196.7
Obligations Under Operating Leases 38.2
34.7
Deferred Credits and Other Noncurrent Liabilities 115.4
114.3
TOTAL NONCURRENT LIABILITIES 4,739.6
4,716.4

TOTAL LIABILITIES 5,486.0
5,391.1

Rate Matters (Note 4)

Commitments and Contingencies (Note 5)

EQUITY
Common Stock – Par Value – $18 Per Share:
Authorized – 7,600,000 Shares
Outstanding – 7,536,640 Shares 135.7
135.7
Paid-in Capital 676.6
676.6
Retained Earnings 1,646.2
1,629.5
Accumulated Other Comprehensive Income (Loss) (1.3 ) (1.3 )
TOTAL COMMON SHAREHOLDER’S EQUITY 2,457.2
2,440.5

Noncontrolling Interest 0.9
0.6

TOTAL EQUITY 2,458.1
2,441.1

TOTAL LIABILITIES AND EQUITY $ 7,944.1
$ 7,832.2



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, ~~2020~~2021 and ~~2019~~2020

(in millions)

(Unaudited)


	Three Months Ended March 31,
	2021		2020
OPERATING ACTIVITIES
Net Income	$	63.4	$	16.1
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	69.6		67.3
Deferred Income Taxes	8.6		(9.2)

Allowance for Equity Funds Used During Construction	(2.1)		(1.4)
Mark-to-Market of Risk Management Contracts	1.1		3.9

Property Taxes	(61.6)		(49.0)
Deferred Fuel Over/Under-Recovery, Net	(461.1)		21.0
Change in Regulatory Assets	(89.1)		(15.1)
Change in Other Noncurrent Assets	6.1		11.1
Change in Other Noncurrent Liabilities	16.6		9.8
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(105.8)		11.3
Fuel, Materials and Supplies	0.4		(7.6)
Accounts Payable	95.1		(31.2)
Accrued Taxes, Net	73.9		51.2

Other Current Assets	8.2		(4.0)
Other Current Liabilities	(51.0)		(48.4)
Net Cash Flows from (Used for) Operating Activities	(427.7)		25.8

INVESTING ACTIVITIES
Construction Expenditures	(91.4)		(122.4)

Other Investing Activities	0.1		0.8
Net Cash Flows Used for Investing Activities	(91.3)		(121.6)

FINANCING ACTIVITIES
Capital Contribution from Parent	100.0		0
Issuance of Long-term Debt – Nonaffiliated	496.8		0

Change in Short-term Debt – Nonaffiliated	(30.0)		12.2
Change in Advances from Affiliates, Net	(37.7)		88.2
Retirement of Long-term Debt – Nonaffiliated	(1.6)		(1.6)
Principal Payments for Finance Lease Obligations	(2.6)		(2.7)

Dividends Paid on Common Stock – Nonaffiliated	(1.0)		(0.7)
Other Financing Activities	0.1		0.2
Net Cash Flows from Financing Activities	524.0		95.6

Net Increase (Decrease) in Cash and Cash Equivalents	5.0		(0.2)
Cash and Cash Equivalents at Beginning of Period	13.2		1.6
Cash and Cash Equivalents at End of Period	$	18.2	$	1.4

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	39.7	$	40.7

Noncash Acquisitions Under Finance Leases	1.5		3.0
Construction Expenditures Included in Current Liabilities as of March 31,	40.2		45.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

113

Three Months Ended March 31,
2020 2019
OPERATING ACTIVITIES

Net Income $ 16.1
$ 29.0
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 67.3
62.1
Deferred Income Taxes (9.2 ) (2.5 )
Allowance for Equity Funds Used During Construction (1.4 ) (1.8 )
Mark-to-Market of Risk Management Contracts 3.9
2.3
Property Taxes (49.0 ) (48.9 )
Deferred Fuel Over/Under-Recovery, Net 21.0
10.3
Change in Other Noncurrent Assets (4.0 ) 2.9
Change in Other Noncurrent Liabilities 9.8
7.9
Changes in Certain Components of Working Capital:
Accounts Receivable, Net 11.3
6.3
Fuel, Materials and Supplies (7.6 ) (16.2 )
Accounts Payable (31.2 ) (55.0 )
Accrued Taxes, Net 51.2
52.7
Accrued Interest (12.7 ) (12.7 )
Other Current Assets (4.0 ) (10.0 )
Other Current Liabilities (35.7 ) (17.0 )
Net Cash Flows from Operating Activities 25.8
9.4

INVESTING ACTIVITIES
Construction Expenditures (122.4 ) (86.6 )
Change in Advances to Affiliates, Net —
81.4
Other Investing Activities 0.8
(3.1 )
Net Cash Flows Used for Investing Activities (121.6 ) (8.3 )

FINANCING ACTIVITIES
Change in Short-term Debt – Nonaffiliated 12.2
—
Change in Advances from Affiliates, Net 88.2
74.0
Retirement of Long-term Debt – Nonaffiliated (1.6 ) (55.1 )
Principal Payments for Finance Lease Obligations (2.7 ) (2.7 )
Dividends Paid on Common Stock —
(18.7 )
Dividends Paid on Common Stock – Nonaffiliated (0.7 ) (1.1 )
Other Financing Activities 0.2
0.1
Net Cash Flows from (Used for) Financing Activities 95.6
(3.5 )

Net Decrease in Cash and Cash Equivalents (0.2 ) (2.4 )
Cash and Cash Equivalents at Beginning of Period 1.6
24.5
Cash and Cash Equivalents at End of Period $ 1.4
$ 22.1

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 40.7
$ 40.5
Net Cash Paid for Income Taxes —
0.2
Noncash Acquisitions Under Finance Leases 3.0
0.8
Construction Expenditures Included in Current Liabilities as of March 31, 45.2
44.8



~~See Condensed Notes to Condensed Financial Statements of Registrants beginning on page~~ ~~110~~.

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS

The condensed notes to condensed financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise:

Note

Registrant

Page
Number

~~Note~~

~~Registrant~~

~~Page~~

~~Number~~

Significant Accounting Matters

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~111~~115

New Accounting Standards

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~113~~117

Comprehensive Income

AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

~~114~~118

Rate Matters

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~118~~122

Commitments, Guarantees and Contingencies

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~126~~136

Acquisitions ~~and Impairments~~

AEP, APCo

~~131~~141

Benefit Plans

AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

~~132~~142

Business Segments

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~134~~144

Derivatives and Hedging

AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

~~139~~149

Fair Value Measurements

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~150~~162

Income Taxes

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~165~~178

Financing Activities

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~167~~180

Revenue from Contracts with Customers

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

~~174~~188

114

1. SIGNIFICANT ACCOUNTING MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, ~~2020~~2021 is not necessarily indicative of results that may be expected for the year ending December 31, ~~2020.~~2021. The condensed financial statements are unaudited and should be read in conjunction with the audited ~~2019~~2020 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February ~~20, 2020.~~25, 2021.

COVID-19

As of March 31, ~~2020~~2021 and through the date of this report, the Registrants assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, the allowance for credit losses and the carrying value of long-lived assets. While there were not any impairments or significant increases in credit allowances resulting from these assessments ~~as of and~~ for the ~~quarter~~three months ended March 31, 2021 and 2020, the ultimate impact of COVID-19 also depends on factors beyond management’s knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, management cannot estimate the potential future impact to financial position, results of operations and cash flows, but the impacts could be material.

115

Earnings Per Share (EPS) (Applies to AEP)

Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted-average outstanding common shares, assuming conversion of all potentially dilutive stock awards.

The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:


	Three Months Ended March 31,
	2021				2020
	(in millions, except per share data)
			$/share				$/share


Earnings Attributable to AEP Common Shareholders	$	575.0			$	495.2

Weighted-Average Number of Basic AEP Common Shares Outstanding	497.1		$	1.16	494.6		$	1.00
Weighted-Average Dilutive Effect of Stock-Based Awards	1.1		(0.01)		2.0		0
Weighted-Average Number of Diluted AEP Common Shares Outstanding	498.2		$	1.15	496.6		$	1.00

Three Months Ended March 31,
2020 2019
(in millions, except per share data)

$/share $/share
Earnings Attributable to AEP Common Shareholders $ 495.2

$ 572.8

Weighted Average Number of Basic Shares Outstanding 494.6
$ 1.00
493.3
$ 1.16
Weighted Average Dilutive Effect of Stock-Based Awards 2.0
—
1.2
—
Weighted Average Number of Diluted Shares Outstanding 496.6
$ 1.00
494.5
$ 1.16

Equity Units ~~issued in March 2019~~ are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, as the dilutive stock price ~~threshold was~~thresholds were not met. See Note 12 - Financing Activities for more information related to Equity Units.

There were 0 and 697 thousand ~~and 0~~ antidilutive shares outstanding as of March 31, ~~2020~~2021 and ~~2019,~~2020, respectively. The

antidilutive shares were excluded from the calculation of diluted EPS.

Restricted Cash (Applies to AEP, AEP Texas and APCo)

Restricted Cash primarily ~~included~~includes funds held by ~~trustee~~trustees for the payment of securitization ~~bonds and contractually restricted deposits held for the future payment of the remaining construction activities at Santa Rita East.~~bonds.

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statements of cash flows:


	March 31, 2021
	AEP		AEP Texas		APCo
	(in millions)
Cash and Cash Equivalents	$	273.2	$	0.1	$	4.8
Restricted Cash	50.8		39.3		11.6
Total Cash, Cash Equivalents and Restricted Cash	$	324.0	$	39.4	$	16.4

March 31, 2020
AEP AEP Texas APCo
(in millions)
Cash and Cash Equivalents $ 1,554.6
$ 0.1
$ 2.8
Restricted Cash 116.2
100.1
15.7
Total Cash, Cash Equivalents and Restricted Cash $ 1,670.8
$ 100.2
$ 18.5

December 31, 2019
AEP AEP Texas APCo
(in millions)
Cash and Cash Equivalents $ 246.8
$ 3.1
$ 3.3
Restricted Cash 185.8
154.7
23.5
Total Cash, Cash Equivalents and Restricted Cash $ 432.6
$ 157.8
$ 26.8


	December 31, 2020
	AEP		AEP Texas		APCo
	(in millions)
Cash and Cash Equivalents	$	392.7	$	0.1	$	5.8
Restricted Cash	45.6		28.7		16.9
Total Cash, Cash Equivalents and Restricted Cash	$	438.3	$	28.8	$	22.7

~~SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~

~~Allowance for Uncollectible Accounts~~

Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. The assessment is performed separately by each participating AEP subsidiary, which inherently contemplates any differences in geographical risk characteristics for the allowance. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified. In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for Credit Losses. Management’s assessments contemplate expected losses over the life of the accounts receivable.

116

2. NEW ACCOUNTING STANDARDS

The disclosures in this note apply to all Registrants unless indicated otherwise.

During the FASB’s standard-setting process and upon issuance of final standards, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. ~~The following~~There are no new standards ~~will impact the financial statements.~~

~~ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13)~~

~~In June 2016, the FASB issued ASU 2016-13 requiring the recognition of an allowance for~~ expected credit losses for financial instruments within its scope. Examples of financial instruments that are in scope include trade receivables, certain financial guarantees and held-to-maturity debt securities. The allowance for expected credit losses should be based on historical information, current conditions and reasonable and supportable forecasts. Entities are required to evaluate, and if necessary, recognize expected credit losses at the inception or initial acquisition of a financial instrument (or pool of financial instruments that share similar risk characteristics) subject to ASU 2016-13, and subsequently as of each reporting date. The new standard also revises the other-than-temporary impairment model for available-for-sale debt securities.

New standard implementation activities included: (a) the identification and evaluation of the population of financial instruments within the AEP system that are subject to the new standard, (b) the development of supporting valuation models to also contemplate appropriate metrics for current and supportable forecasted information and (c) the development of disclosures to comply with the requirements of ASU 2016-13. As required by ASU 2016-13, the financial instruments subject to the new standard were evaluated on a pool-basis to the extent such financial instruments shared similar risk characteristics.

Management adopted ASU 2016-13 and its related implementation guidance effective January 1, 2020, by means of an immaterial cumulative-effect adjustment to Retained Earnings on the balance sheets. The adoption of the new standard did not have a material impact ~~to financial position and had no impact~~ on the ~~results of operations or cash flows. Additionally, the adoption of the new standard did not result in any changes to current accounting systems.~~Registrants’ financial statements.

~~ASU 2020-04 “Reference Rate Reform: Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (ASU 2020-04)~~

In March 2020, the FASB issued ASU 2020-04 providing guidance to ease the potential burden in accounting for Reference Rate Reform on financial reporting. The new standard is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference the London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of Reference Rate Reform. The new standard establishes a general contract modification principle that entities can apply in other areas that may be affected by Reference Rate Reform and certain elective hedge accounting expedients. Under the new standard, an entity may make a one-time election to sell or to transfer to the available-for-sale or trading classifications (or both sell and transfer), debt securities that both reference an affected rate, and were classified as held-to-maturity before January 1, 2020.

The new accounting guidance is effective for all entities as of March 12, 2020 through December 31, 2022. The amendments may be applied to contract modifications as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. The amendments may be applied to eligible hedging relationships existing as of the beginning of the interim period that includes March 12, 2020 and to new eligible hedging relationships entered into after the beginning of the interim period that includes March 12, 2020. The one-time election to sell, transfer, or both sell and transfer debt securities classified as held-to-maturity may be made at any time after March 12, 2020 but no later than December 31, 2022. Management has yet to apply the amendments in the new standard to any contract modifications, hedging relationships, or debt securities. Management is analyzing the impact of this new standard and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows.

117

3. COMPREHENSIVE INCOME

The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional ~~details.~~information.

AEP


	Cash Flow Hedges					Pension
Three Months Ended March 31, 2021	Commodity		Interest Rate			and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2020	$	(60.6)	$	(47.5)		$	23.0	$	(85.1)
Change in Fair Value Recognized in AOCI	177.3		13.1		(a)	0		190.4
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)	0.8		0			0		0.8
Purchased Electricity for Resale (b)	(172.0)		0			0		(172.0)
Interest Expense (b)	0		1.5			0		1.5
Amortization of Prior Service Cost (Credit)	0		0			(4.8)		(4.8)
Amortization of Actuarial (Gains) Losses	0		0			2.3		2.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(171.2)		1.5			(2.5)		(172.2)
Income Tax (Expense) Benefit	(36.0)		0.4			(0.5)		(36.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(135.2)		1.1			(2.0)		(136.1)
Net Current Period Other Comprehensive Income (Loss)	42.1		14.2			(2.0)		54.3
Balance in AOCI as of March 31, 2021	$	(18.5)	$	(33.3)		$	21.0	$	(30.8)

Cash Flow Hedges Pension
Three Months Ended March 31, 2020 Commodity Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2019 $ (103.5 ) $ (11.5 ) $ (32.7 ) $ (147.7 )
Change in Fair Value Recognized in AOCI (65.3 ) (42.7 ) (a) —
(108.0 )
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (a) (0.1 ) —
—
(0.1 )
Purchased Electricity for Resale (b) 51.1
—
—
51.1
Interest Expense (b) —
0.9
—
0.9
Amortization of Prior Service Cost (Credit) —
—
(4.9 ) (4.9 )
Amortization of Actuarial (Gains) Losses —
—
2.6
2.6
Reclassifications from AOCI, before Income Tax (Expense) Benefit 51.0
0.9
(2.3 ) 49.6
Income Tax (Expense) Benefit 10.7
0.2
(0.5 ) 10.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 40.3
0.7
(1.8 ) 39.2
Net Current Period Other Comprehensive Income (Loss) (25.0 ) (42.0 ) (1.8 ) (68.8 )
Balance in AOCI as of March 31, 2020 $ (128.5 ) $ (53.5 ) $ (34.5 ) $ (216.5 )

Cash Flow Hedges Pension
Three Months Ended March 31, 2019 Commodity Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2018 $ (23.0 ) $ (12.6 ) $ (84.8 ) $ (120.4 )
Change in Fair Value Recognized in AOCI (38.8 ) —
—
(38.8 )
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity for Resale (b) 12.3
—
—
12.3
Interest Expense (b) —
0.2
—
0.2
Amortization of Prior Service Cost (Credit) —
—
(4.8 ) (4.8 )
Amortization of Actuarial (Gains) Losses —
—
3.0
3.0
Reclassifications from AOCI, before Income Tax (Expense) Benefit 12.3
0.2
(1.8 ) 10.7
Income Tax (Expense) Benefit 2.6
—
(0.4 ) 2.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 9.7
0.2
(1.4 ) 8.5
Net Current Period Other Comprehensive Income (Loss) (29.1 ) 0.2
(1.4 ) (30.3 )
Balance in AOCI as of March 31, 2019 $ (52.1 ) $ (12.4 ) $ (86.2 ) $ (150.7 )

~~AEP Texas~~

Cash Flow Hedge – Pension
Three Months Ended March 31, 2020 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2019 $ (3.4 ) $ (9.4 ) $ (12.8 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.4
—
0.4
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.4
—
0.4
Income Tax (Expense) Benefit 0.1
—
0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.3
—
0.3
Net Current Period Other Comprehensive Income (Loss) 0.3
—
0.3
Balance in AOCI as of March 31, 2020 $ (3.1 ) $ (9.4 ) $ (12.5 )

Cash Flow Hedge – Pension
Three Months Ended March 31, 2019 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2018 $ (4.4 ) $ (10.7 ) $ (15.1 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.4
—
0.4
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.4
—
0.4
Income Tax (Expense) Benefit 0.1
—
0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.3
—
0.3
Net Current Period Other Comprehensive Income (Loss) 0.3
—
0.3
Balance in AOCI as of March 31, 2019 $ (4.1 ) $ (10.7 ) $ (14.8 )

~~APCo~~

Cash Flow Hedge – Pension
Three Months Ended March 31, 2020 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2019 $ 0.9
$ 4.1
$ 5.0
Change in Fair Value Recognized in AOCI (3.9 ) —
(3.9 )
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) (0.4 ) —
(0.4 )
Amortization of Prior Service Cost (Credit) —
(1.3 ) (1.3 )
Amortization of Actuarial (Gains) Losses —
0.1
0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.4 ) (1.2 ) (1.6 )
Income Tax (Expense) Benefit (0.1 ) (0.3 ) (0.4 )
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.3 ) (0.9 ) (1.2 )
Net Current Period Other Comprehensive Income (Loss) (4.2 ) (0.9 ) (5.1 )
Balance in AOCI as of March 31, 2020 $ (3.3 ) $ 3.2
$ (0.1 )

Cash Flow Hedge – Pension
Three Months Ended March 31, 2019 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2018 $ 1.8
$ (6.8 ) $ (5.0 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) (0.3 ) —
(0.3 )
Amortization of Prior Service Cost (Credit) —
(1.3 ) (1.3 )
Amortization of Actuarial (Gains) Losses —
0.5
0.5
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.3 ) (0.8 ) (1.1 )
Income Tax (Expense) Benefit (0.1 ) (0.2 ) (0.3 )
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.2 ) (0.6 ) (0.8 )
Net Current Period Other Comprehensive Income (Loss) (0.2 ) (0.6 ) (0.8 )
Balance in AOCI as of March 31, 2019 $ 1.6
$ (7.4 ) $ (5.8 )

~~I&M~~

Cash Flow Hedge – Pension
Three Months Ended March 31, 2020 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2019 $ (9.9 ) $ (1.7 ) $ (11.6 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.5
—
0.5
Amortization of Prior Service Cost (Credit) —
(0.2 ) (0.2 )
Amortization of Actuarial (Gains) Losses —
0.2
0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.5
—
0.5
Income Tax (Expense) Benefit 0.1
—
0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.4
—
0.4
Net Current Period Other Comprehensive Income (Loss) 0.4
—
0.4
Balance in AOCI as of March 31, 2020 $ (9.5 ) $ (1.7 ) $ (11.2 )

Cash Flow Hedge – Pension
Three Months Ended March 31, 2019 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2018 $ (11.5 ) $ (2.3 ) $ (13.8 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.5
—
0.5
Amortization of Prior Service Cost (Credit) —
(0.2 ) (0.2 )
Amortization of Actuarial (Gains) Losses —
0.2
0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.5
—
0.5
Income Tax (Expense) Benefit 0.1
—
0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.4
—
0.4
Net Current Period Other Comprehensive Income (Loss) 0.4
—
0.4
Balance in AOCI as of March 31, 2019 $ (11.1 ) $ (2.3 ) $ (13.4 )

~~OPCo~~


	Cash Flow Hedges					Pension
Three Months Ended March 31, 2020	Commodity		Interest Rate			and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2019	$	(103.5)	$	(11.5)		$	(32.7)	$	(147.7)
Change in Fair Value Recognized in AOCI	(65.3)		(42.7)		(a)	0		(108.0)
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)	(0.1)		0			0		(0.1)
Purchased Electricity for Resale (b)	51.1		0			0		51.1
Interest Expense (b)	0		0.9			0		0.9
Amortization of Prior Service Cost (Credit)	0		0			(4.9)		(4.9)
Amortization of Actuarial (Gains) Losses	0		0			2.6		2.6
Reclassifications from AOCI, before Income Tax (Expense) Benefit	51.0		0.9			(2.3)		49.6
Income Tax (Expense) Benefit	10.7		0.2			(0.5)		10.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	40.3		0.7			(1.8)		39.2
Net Current Period Other Comprehensive Income (Loss)	(25.0)		(42.0)			(1.8)		(68.8)
Balance in AOCI as of March 31, 2020	$	(128.5)	$	(53.5)		$	(34.5)	$	(216.5)

118

AEP Texas


		Cash Flow Hedge –		Pension
Three Months Ended March 31, 2021		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2020		$	(2.3)	$	(6.6)	$	(8.9)
Change in Fair Value Recognized in AOCI		0.1		0		0.1
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		0.3		0		0.3


Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.3		0		0.3
Income Tax (Expense) Benefit		0.1		0		0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.2		0		0.2
Net Current Period Other Comprehensive Income (Loss)		0.3		0		0.3
Balance in AOCI as of March 31, 2021		$	(2.0)	$	(6.6)	$	(8.6)


		Cash Flow Hedge –		Pension
Three Months Ended March 31, 2020		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2019		$	(3.4)	$	(9.4)	$	(12.8)
Change in Fair Value Recognized in AOCI		0		0		0
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		0.4		0		0.4


Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.4		0		0.4
Income Tax (Expense) Benefit		0.1		0		0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.3		0		0.3
Net Current Period Other Comprehensive Income (Loss)		0.3		0		0.3
Balance in AOCI as of March 31, 2020		$	(3.1)	$	(9.4)	$	(12.5)

APCo


		Cash Flow Hedge –		Pension
Three Months Ended March 31, 2021		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2020		$	(0.8)	$	8.0	$	7.2
Change in Fair Value Recognized in AOCI		9.3		0		9.3
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		(0.4)		0		(0.4)
Amortization of Prior Service Cost (Credit)		0		(1.4)		(1.4)

Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.4)		(1.4)		(1.8)
Income Tax (Expense) Benefit		(0.1)		(0.3)		(0.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.3)		(1.1)		(1.4)
Net Current Period Other Comprehensive Income (Loss)		9.0		(1.1)		7.9
Balance in AOCI as of March 31, 2021		$	8.2	$	6.9	$	15.1


		Cash Flow Hedge –		Pension
Three Months Ended March 31, 2020		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2019		$	0.9	$	4.1	$	5.0
Change in Fair Value Recognized in AOCI		(3.9)		0		(3.9)
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		(0.4)		0		(0.4)
Amortization of Prior Service Cost (Credit)		0		(1.3)		(1.3)
Amortization of Actuarial (Gains) Losses		0		0.1		0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.4)		(1.2)		(1.6)
Income Tax (Expense) Benefit		(0.1)		(0.3)		(0.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.3)		(0.9)		(1.2)
Net Current Period Other Comprehensive Income (Loss)		(4.2)		(0.9)		(5.1)
Balance in AOCI as of March 31, 2020		$	(3.3)	$	3.2	$	(0.1)

119


I&M
		Cash Flow Hedge –		Pension
Three Months Ended March 31, 2021		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2020		$	(8.3)	$	1.3	$	(7.0)
Change in Fair Value Recognized in AOCI		0		0		0
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		0.6		0		0.6
Amortization of Prior Service Cost (Credit)		0		(0.2)		(0.2)
Amortization of Actuarial (Gains) Losses		0		0.2		0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.6		0		0.6
Income Tax (Expense) Benefit		0.1		0		0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.5		0		0.5
Net Current Period Other Comprehensive Income (Loss)		0.5		0		0.5
Balance in AOCI as of March 31, 2021		$	(7.8)	$	1.3	$	(6.5)


		Cash Flow Hedge –		Pension
Three Months Ended March 31, 2020		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2019		$	(9.9)	$	(1.7)	$	(11.6)
Change in Fair Value Recognized in AOCI		0		0		0
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		0.5		0		0.5
Amortization of Prior Service Cost (Credit)		0		(0.2)		(0.2)
Amortization of Actuarial (Gains) Losses		0		0.2		0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.5		0		0.5
Income Tax (Expense) Benefit		0.1		0		0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.4		0		0.4
Net Current Period Other Comprehensive Income (Loss)		0.4		0		0.4
Balance in AOCI as of March 31, 2020		$	(9.5)	$	(1.7)	$	(11.2)


OPCo
			Cash Flow Hedge –
Three Months Ended March 31, ~~2020~~2021			Interest Rate
		(in millions)
Balance in AOCI as of December 31, ~~2019~~2020	$	—	$	0
Change in Fair Value Recognized in AOCI	—		0
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)	—		0


Reclassifications from AOCI, before Income Tax (Expense) Benefit			0
Income Tax (Expense) Benefit			0
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit			0
Net Current Period Other Comprehensive Income (Loss)			0
Balance in AOCI as of March 31, 2021			$	0


		Cash Flow Hedge –
Three Months Ended March 31, 2020		Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2019		$	0
Change in Fair Value Recognized in AOCI		0
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		0


Reclassifications from AOCI, before Income Tax (Expense) Benefit		0
Income Tax (Expense) Benefit		0
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0
Net Current Period Other Comprehensive Income (Loss)		0
Balance in AOCI as of March 31, 2020		$	0

120


PSO
			Cash Flow Hedge –
Three Months Ended March 31, 2021			Interest Rate
		(in millions)
Balance in AOCI as of December 31, 2020			$	0.1
Change in Fair Value Recognized in AOCI			0
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)			(0.1)


Reclassifications from AOCI, before Income Tax (Expense) Benefit	—		(0.1)
Income Tax (Expense) Benefit	—		0
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	—		(0.1)
Net Current Period Other Comprehensive Income (Loss)	—		(0.1)
Balance in AOCI as of March 31, 2021			$	0


			Cash Flow Hedge –
Three Months Ended March 31, 2020			Interest Rate
		(in millions)
Balance in AOCI as of December 31, 2019			$	1.1
Change in Fair Value Recognized in AOCI			0
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)			(0.3)


Reclassifications from AOCI, before Income Tax (Expense) Benefit			(0.3)
Income Tax (Expense) Benefit			(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit			(0.2)
Net Current Period Other Comprehensive Income (Loss)			(0.2)
Balance in AOCI as of March 31, 2020	$	—	$	0.9

Cash Flow Hedge –
Three Months Ended March 31, 2019 Interest Rate
(in millions)
Balance in AOCI as of December 31, 2018 $ 1.0
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) (0.4 )
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.4 )
Income Tax (Expense) Benefit (0.1 )
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.3 )
Net Current Period Other Comprehensive Income (Loss) (0.3 )
Balance in AOCI as of March 31, 2019 $ 0.7

~~PSO~~

Cash Flow Hedge –
Three Months Ended March 31, 2020 Interest Rate
(in millions)
Balance in AOCI as of December 31, 2019 $ 1.1
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) (0.3 )
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.3 )
Income Tax (Expense) Benefit (0.1 )
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.2 )
Net Current Period Other Comprehensive Income (Loss) (0.2 )
Balance in AOCI as of March 31, 2020 $ 0.9

Cash Flow Hedge –
Three Months Ended March 31, 2019 Interest Rate
(in millions)
Balance in AOCI as of December 31, 2018 $ 2.1
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) (0.3 )
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.3 )
Income Tax (Expense) Benefit (0.1 )
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.2 )
Net Current Period Other Comprehensive Income (Loss) (0.2 )
Balance in AOCI as of March 31, 2019 $ 1.9

~~SWEPCo~~

Cash Flow Hedge – Pension
Three Months Ended March 31, 2020 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2019 $ (1.8 ) $ 0.5
$ (1.3 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.5
—
0.5
Amortization of Prior Service Cost (Credit) —
(0.5 ) (0.5 )
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.5
(0.5 ) —
Income Tax (Expense) Benefit 0.1
(0.1 ) —
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.4
(0.4 ) —
Net Current Period Other Comprehensive Income (Loss) 0.4
(0.4 ) —
Balance in AOCI as of March 31, 2020 $ (1.4 ) $ 0.1
$ (1.3 )

Cash Flow Hedge – Pension
Three Months Ended March 31, 2019 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2018 $ (3.3 ) $ (2.1 ) $ (5.4 )
Change in Fair Value Recognized in AOCI —
—
—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.5
—
0.5
Amortization of Prior Service Cost (Credit) —
(0.5 ) (0.5 )
Amortization of Actuarial (Gains) Losses —
0.1
0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.5
(0.4 ) 0.1
Income Tax (Expense) Benefit 0.1
(0.1 ) —
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.4
(0.3 ) 0.1
Net Current Period Other Comprehensive Income (Loss) 0.4
(0.3 ) 0.1
Balance in AOCI as of March 31, 2019 $ (2.9 ) $ (2.4 ) $ (5.3 )

~~(a)~~

The change in fair value includes $5 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC for the three months ended March 31, 2020.

~~(b)~~

~~Amounts reclassified to the referenced line item on the statements of income.~~

(a)The change in fair value includes $4 million and $5 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC for the three months ended March 31, 2021 and 2020, respectively.

(b)Amounts reclassified to the referenced line item on the statements of income.

The disclosures in this note apply to all Registrants unless indicated otherwise.

As discussed in the ~~2019~~2020 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~~2020 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~~2021 and updates the ~~2019~~2020 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.

Regulated Generating Units that have been Retired

In September 2020, the Oklaunion Power Station was retired. As of March 31, 2021, PSO has a regulatory asset for accelerated depreciation pending approval recorded on its balance sheet of $34 million. PSO will seek recovery of the Oklaunion Power Station in its next base rate case. In October 2020, the Oklaunion Power Station site was sold to a nonaffiliated third-party.

In April 2016, Welsh Plant, Unit 2 was retired. As part of the 2016 Texas Base Rate Case, SWEPCo received approval from the PUCT to recover the Texas jurisdictional share of Welsh Plant, Unit 2. See “2016 Texas Base Rate Case” section of Note 4 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. As of March 31, 2021, SWEPCo has 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. See “2020 Louisiana Base Rate Case” section below for additional information.

Regulated Generating Units to be Retired ~~(Applies to AEP, PSO and SWEPCo)~~

In ~~September 2018, management announced that~~2014, PSO received final approval from the ~~Oklaunion Power Station~~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 ~~probable~~being deferred as a regulatory asset. In 2016, as part of ~~abandonment and is expected to be retired by October 2020.~~ the 2015 Oklahoma Base Rate Case, the OCC issued an order approving the continued depreciation of Northeastern Plant, Unit 3 through 2040. The order did not approve accelerating the recovery of the incremental depreciation based on the revised retirement date of 2026.

In January 2020, as part of the 2019 Arkansas Base Rate Case, management announced that the Dolet Hills Power Station was probable of abandonment and was to be retired by December 2026. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation. In March 2020, management announced plans to ~~accelerate~~retire the ~~expected retirement date~~plant in 2021.

In November 2020, management announced plans to retire Pirkey Power Plant in 2023 and that it will cease using coal at the ~~end~~Welsh Plant in 2028. As a result of ~~September 2021.~~the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation.

The table below summarizes the ~~plant investment and their~~net book value including CWIP, before cost of removal ~~currently being recovered, as well as the regulatory assets for accelerated depreciation for the generating units~~and materials and supplies, as of March 31, ~~2020.~~2021, of generating facilities planned for early retirement:

Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo)

$20 million, ~~that will be billed to SWEPCo prior to~~excluding impacts of the ~~closure of~~February 2021 severe winter weather event, which includes fuel consumed at 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.

In March 2021, the APSC approved fuel rates that provide recovery of the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Pirkey Power Plant and Related Fuel Operations (Applies to AEP and SWEPCo)

In November 2020, management announced plans to retire the Pirkey Power Plant in 2023. The Pirkey Power Plant costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Pirkey Power Plant is $209 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 $163 millionas of March 31, 2021. Also, as of March 31, 2021, SWEPCo had a net over-recovered fuel balance of $20 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Pirkey Power Plant. Additional operational costs are expected to be incurred by Sabine and billed to SWEPCo, as well as land-related costs incurred by SWEPCo, prior to the closure of the Pirkey Power Plant and recovered through fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2020 Texas Fuel Reconciliation (Applies to AEP and SWEPCo)

In June 2020, SWEPCo filed a fuel reconciliation with the PUCT for its retail operations in Texas for the reconciliation period of March 1, 2017 to December 31, 2019. The fuel reconciliation included total fuel costs of $1.7 billion ($616 million of which is related to the Texas jurisdiction). In January 2021, various parties filed testimony recommending fuel cost disallowances totaling $125 million relating to the Texas jurisdiction. Also in January 2021, SWEPCo filed rebuttal testimony disputing the recommended disallowances. In February 2021, SWEPCo and various parties reached a settlement in principle which resulted in an immaterial impact to SWEPCo’s 2020 financial statements. If additional costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)


	AEP
	March 31,		December 31,
	2021		2020
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs (a)	$	1,185.0	$	0
Dolet Hills Power Station Accelerated Depreciation	92.6		71.2
Kentucky Deferred Purchase Power Expenses	42.8		41.3
Plant Retirement Costs – Unrecovered Plant, Louisiana	35.2		35.2
Oklaunion Power Station Accelerated Depreciation	34.0		34.4

Pirkey Power Plant Accelerated Depreciation	30.8		12.2
Other Regulatory Assets Pending Final Regulatory Approval	37.5		26.4
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	285.0		134.2
Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		25.9
COVID-19	19.5		24.9
Environmental Expense Deferral - Virginia	12.3		9.3


Other Regulatory Assets Pending Final Regulatory Approval	33.0		27.2
Total Regulatory Assets Pending Final Regulatory Approval	$	1,833.6	$	442.2

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

(a)PSO and SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. See “Impacts of Severe Winter Weather” section below for additional information.

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

Regulatory Assets Currently Not Earning a Return
Vegetation Management Program (a) $ 3.8
$ 29.4
Other Regulatory Assets Pending Final Regulatory Approval 1.5
1.4
Total Regulatory Assets Pending Final Regulatory Approval $ 5.3
$ 30.8

Plant Retirement Costs – Materials and Supplies

Plant Retirement Costs – Asset Retirement Obligation Costs

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


	AEP Texas
	March 31,		December 31,
	2021		2020
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Advanced Metering System	$	16.4	$	16.3
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	10.5		0.8
COVID-19	8.6		10.5
Texas Retail Electric Provider Bad Debt Expense	4.1		0
Vegetation Management Program	3.8		3.8
Other Regulatory Assets Pending Final Regulatory Approval	2.6		1.5
Total Regulatory Assets Pending Final Regulatory Approval	$	46.0	$	32.9

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


	APCo
	March 31,		December 31,
	2021		2020
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
COVID-19 – Virginia	$	4.0	$	3.7

Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	49.1		3.4
Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		25.9
Environmental Expense Deferral - Virginia	12.3		9.3
COVID-19 – West Virginia	1.6		1.5

Total Regulatory Assets Pending Final Regulatory Approval	$	92.9	$	43.8


	I&M
	March 31,		December 31,
	2021		2020
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval	$	0	$	0.5
Regulatory Assets Currently Not Earning a Return
COVID-19	2.8		3.8

Other Regulatory Assets Pending Final Regulatory Approval	0.6		0
Total Regulatory Assets Pending Final Regulatory Approval	$	3.4	$	4.3


	PSO
	March 31,		December 31,
	2021		2020
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs (a)	$	688.7	$	0
Oklaunion Power Station Accelerated Depreciation	34.0		34.4

Regulatory Assets Currently Not Earning a Return


Storm-Related Costs	24.8		15.8
Other Regulatory Assets Pending Final Regulatory Approval	0.8		0.3
Total Regulatory Assets Pending Final Regulatory Approval	$	748.3	$	50.5


	SWEPCo
	March 31,		December 31,
	2021		2020
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs (a)	$	496.3	$	0
Dolet Hills Power Station Accelerated Depreciation	92.6		71.2
Plant Retirement Costs – Unrecovered Plant, Louisiana	35.2		35.2
Pirkey Power Plant Accelerated Depreciation	30.8		12.2
Welsh Plant, Units 1 and 3 Accelerated Depreciation	14.2		3.6
Other Regulatory Assets Pending Final Regulatory Approval	2.8		2.2
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	139.1		99.3
Asset Retirement Obligation - Louisiana	9.4		9.1



Other Regulatory Assets Pending Final Regulatory Approval	15.4		14.5
Total Regulatory Assets Pending Final Regulatory Approval	$	835.8	$	247.3

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

Impacts of Severe Winter Weather

Storm Restoration Costs (Applies to AEP, APCo and SWEPCo)

In February 2021, severe winter weather impacted the service territories of APCo, KPCo and SWEPCo resulting in power outages and extensive damage to transmission and distribution infrastructures. As a result, incremental restoration expenses have been deferred related to the severe winter weather. The current estimate of storm restoration costs are as follows:


		March 31, 2021
Company	Jurisdiction	Capital		O&M		Regulatory Asset		Total
		(in millions)
APCo	Virginia	$	5.4	$	2.2	$	5.6	$	13.2
APCo	West Virginia	19.6		0		39.1		58.7
SWEPCo	Louisiana	4.9		0		42.1		47.0
KPCo	Kentucky	26.7		3.8		44.1		74.6
	Total	$	56.6	$	6.0	$	130.9	$	193.5

The amounts in the table above represent estimates as of March 31, 2021, and are subject to true-up as additional information becomes available. In March 2021, the LPSC approved the deferral of incremental other operation and maintenance storm restoration expenses related to the Louisiana jurisdiction for SWEPCo. Similarly, in April 2021, the KPSC approved deferral of KPCo’s incremental other operation and maintenance storm restoration expenses. APCo and KPCo intend to seek recovery of these incremental storm restoration costs in their next respective base rate cases while SWEPCo is expected to seek recovery in a separate filing. If any of the restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

February 2021 Severe Winter Weather Impacts in SPP (Applies to AEP, PSO and SWEPCo)

The February 2021 severe winter weather also 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. From February 9, 2021, to February 20, 2021, PSO’s and SWEPCo’s estimates of natural gas expenses and purchases of electricity to be recovered from customers are as follows:


	PSO		SWEPCo		Total
	(in millions)
Retail Customers (a)	$	688.7	$	496.3	$	1,185.0
Wholesale Customers	0		88.4		88.4
Total	$	688.7	$	584.7	$	1,273.4

The amounts in the table above represent estimates as of March 31, 2021, and are subject to final settlement as additional information becomes available.

PSO and SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. Given the significance of these costs, PSO and SWEPCo expect the costs to be subject to prudency reviews. Management believes these costs are probable of future recovery, but expects the recovery period to be extended to mitigate the impact on customer bills.

Also in March 2021, the LPSC approved a special order granting a temporary modification to the FAC that allows SWEPCo to recover the Louisiana jurisdictional share of the retail fuel costs over a longer period. In April 2021, SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five year recovery period. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

PSO and SWEPCo Cash Flow Implications

ERCOT (Applies to AEP and AEP Texas)

During 2020, AEP’s electric ~~utility~~ operating companies ~~have~~ informed both retail customers and state regulators that disconnections for non-payment ~~have been~~were temporarily suspended. ~~These uncertain~~Shortly thereafter, AEP’s state regulators also imposed temporary moratoria on customary disconnection practices. As of March 31, 2021, AEP’s electric operating companies have resumed customary disconnection practices in all regulated jurisdictions with the exception of Arkansas and Virginia. In March 2021, the APSC issued an order allowing electric utilities in Arkansas to begin disconnections for non-payment beginning on May 3, 2021. AEP continues to work with regulators and stakeholders in Virginia and management currently anticipates resuming customary disconnection practices in the third quarter of 2021. Continuing adverse economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and 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.accounts receivable. 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.~~

AEP Texas Rate Matters (Applies to AEP and AEP Texas)

~~2019 Texas Base Rate Case~~

~~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~~Interim Transmission and Distribution Rates

Through March 31, 2021, AEP Texas’ cumulative revenues from interim base rate increases that ~~will refund $21 million annually of Excess ADIT that is primarily not~~are 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~~review is estimated to ~~December 2019.~~

~~In April 2020, the PUCT issued an order approving a stipulation and settlement agreement. The order includes an annual~~be $118 million. A base rate ~~reduction of $40 million based upon~~review could result in 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 relatedrefund to ~~capital investments recorded through 2018 and $4 million related to rate case expenses. In addition,~~customers if AEP Texas ~~will refund: (a) $77 million of Excess ADIT and excess federal income taxes collected as~~incurs 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 yearsdisallowance of the ~~date~~transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that ~~the final order was issued. The order also states future financially based capital incentives will not be included in~~are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and ~~contains various ring-fencing provisions. As a result of the final order,~~cash flows and impact financial condition. AEP Texas ~~will refund $275 million of Excess ADIT associated with certain depreciable property using ARAM~~is required to ~~transmission customers. AEP Texas will determine how to refund the remaining Excess ADIT that is not subject to normalization requirements in future proceedings.~~file for a comprehensive rate review no later than April 3, 2024.

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.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

2017-2019 Virginia Triennial Review

~~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,~~In November 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~~issued an order on APCo’s ~~Virginia retail~~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 ~~November 2018,~~December 2020, an intervenor filed a petition at the Virginia SCC ~~authorized~~requesting reconsideration of: (a) the failure of the Virginia SCC to apply a ~~ROE~~threshold earnings test to the approved regulatory asset for APCo’s closed coal-fired generation assets, (b) the Virginia SCC’s use of ~~9.42% applicable~~a 2011 benchmark study to measure the replacement value of capacity for purposes of APCo’s 2017 – 2019 earnings test and (c) the reasonableness and prudency of APCo’s investments in AMI meters.

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 on APCo’s ability to earn a fair return through existing base ~~rate earnings for~~rates, APCo further requested that the ~~2017-2019 triennial period.~~Virginia SCC clarify whether it has the authority to also permit an increase in base rates.

In March 2021, an intervenor filed its assignments of error with the Virginia Supreme Court related to the appeal of the November 2020 order in which it stated the Virginia SCC erred: (a) in determining that Virginia law ~~provides~~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 assignments of error with the Virginia Supreme Court related to its appeal of the November 2020 order in which it stated the Virginia SCC erred: (a) in finding that costs associated with asset impairments ~~of retired coal~~related to early retirement determinations made by APCo for certain generation ~~assets, or automated meters, or both, which a utility records as an expense, shall~~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

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retroactively adjusting APCo’s depreciation expense for purposes of calculating APCo’s earnings for the 2017-2019 triennial ~~review proceeding,~~period.

In March 2021, the Virginia SCC issued an order confirming certain of its decisions from the November 2020 order and ~~be deemed recovered.~~rejecting the various requests for reconsideration from APCo and an intervenor. 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 regardingconfirming its decision to reject an intervenor’s recommendation that 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 theseAMI costs ~~to be substantially recovered by APCo~~incurred during the triennial ~~review period.~~period be disallowed, the Virginia SCC clarified that APCo established the need to replace its existing AMR meters, and that based on the uncertainty surrounding the continued manufacturing and support of AMR technology, APCo reasonably chose to replace them with AMI meters. In March 2021, APCo filed a notice of appeal of the reconsideration order with the Virginia Supreme Court. APCo expects to submit its brief before the Virginia Supreme Court in the second or third quarter of 2021.

In April 2021, and in conjunction with APCo’s November 2020 and March 2021 appeals with the Virginia Supreme Court, APCo filed a petition for interim rates with the Virginia Supreme Court (subject to refund with interest and supported by a bond issuance) requesting a $40 million increase in annual APCo Virginia base rates. APCo submitted this filing based on Virginia law that allows the Virginia Supreme Court to authorize interim rates until the final disposition on APCo’s appeals. APCo also requested an expedited schedule from the Virginia Supreme Court on APCo’s appeals.

December 2020 Virginia Environmental Rate Adjustment Clause (E-RAC) Rider Filing

In December 2020, APCo submitted ~~its 2017-2019 Virginia triennial earnings review~~an E-RAC filing ~~and base rate case~~ with the Virginia SCC ~~as required by state law.~~requesting the regulatory approvals necessary to implement CCR/ELG compliance plans at APCo’s Amos and Mountaineer plants. In this filing, APCo requested ~~a $65~~an initial E-RAC revenue requirement of $31 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~~recover CCR/ELG construction costs and ~~a proposed increase in~~ongoing environmental operation and maintenance expenses. APCo’s ~~Virginia depreciation rates and $8 million related to APCo’s calculated shortfall in 2017-2019 APCo’s Virginia earnings. Inclusive~~current estimate of ~~the $93 million expense associated with APCo’s Virginia jurisdictional retired coal-fired plants, APCo calculated its 2017-2019 Virginia earnings~~total company CCR/ELG costs for the ~~triennial period to be below~~Amos and Mountaineer plants, including AFUDC, is approximately $240 million.

In April 2021, intervenors submitted testimony. Testimony included recommendations that APCo construct only the ~~authorized ROE range.~~

CCR-related investments at the Amos and Mountaineer plants and, as a consequence, APCo ~~is currently in~~close the ~~process~~Amos and Mountaineer plants at the end of ~~retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters.~~2028. As of March 31, ~~2020~~2021, APCo’s total company combined CCR and ~~December 31, 2019, APCo has approximately $52~~ELG investment balances in CWIP for these plants were $8 million and ~~$51~~$14 million, of respectively.

Virginia ~~jurisdictional AMR meters recorded~~Staff will submit testimony 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.~~

May 2021 with a hearing scheduled to occur in June 2021. If any APCo ~~Virginia jurisdictional~~CCR/ELG costs are not ~~recoverable or if refunds of revenues collected from customers during the triennial review period are ordered by the Virginia SCC,~~approved for recovery, it ~~could~~would reduce future net income and cash flows and impact financial condition.

131

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

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,~~2021, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be ~~$1.1~~$1.2 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 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for base rate proceedings. The rule requires~~ ETT is required to file for a comprehensive ~~base~~ rate review no later than February 1, ~~2021.~~2023, during which, the $1.2 billion of cumulative revenues above will be subject to review.

I&M Rate Matters (Applies to AEP and I&M)

~~2019~~ Indiana ~~Base Rate Case~~Earnings Test Filings

~~In May 2019,~~ I&M ~~filed~~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 ~~request with~~credit in the ~~IURC~~FAC factor computation for periods in which I&M earned above its authorized return for both the one-year and five-year periods. The credit is determined as 50% of the lower of the one-year or five-year earnings above the authorized level. In July 2021, I&M will submit its FAC filing and earnings test evaluation for the period ended May 2021. As of March 31, 2021, I&M’s financial statements adequately reflect the estimated impact of I&M’s upcoming Indiana earnings test filings. Various uncertainties could impact I&M’s actual earnings and the need for a ~~$172 million annual increase. The requested increase in Indiana rates would be phased in through January 2021~~FAC credit to customers. These uncertainties could also reduce I&M’s overall future net income 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 investmentscash flows 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.~~impact financial condition.

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.

OPCo Rate Matters (Applies to AEP and OPCo)

2020 Ohio Base Rate Case

In ~~April~~June 2020, OPCo filed a ~~pre-filing notice stating its intent to file an application~~request with the PUCO ~~to adjust distribution rates.~~for a $42 million annual increase in base rates based upon a proposed 10.15% ROE net of existing riders. Additionally, OPCo ~~plans to file~~filed a request with the ~~application in May 2020 and also plans to request~~PUCO for a 60-day temporary delay of the normal rate case proceeding due to the COVID-19 ~~pandemic.~~pandemic with rates expected to be effective approximately mid-2021.

In November 2020, the PUCO staff filed testimony supporting an annual revenue decrease ranging from $102 million to $123 million based upon an ROE of 8.76% to 9.78%. The difference between OPCo’s request and the staff testimony are primarily due to reductions in: (a) demand-side management programs of $40 million, (b) ROE ranging from $9 million to $30 million, (c) employee-related expenses of $23 million, (d) rate base of $19 million, (e) property taxes of $17 million, (f) other various expenses of $15 million, (g) depreciation expense of $11 million and (h) vegetation management programs of $10 million which is subject to over/under-recovery through a rider. The staff’s proposed disallowance of plant in service could also result in a write-off of up to $27 million. In addition, the staff recommended that capitalized incentives be excluded from base rates prospectively and also recommended annual revenue caps for the DIR of $57 million in 2021, $78 million in 2022, $96 million in 2023 and $46 million for the first five months of 2024. In December 2020, OPCo and intervenors filed objections.

132

In March 2021, OPCo, the PUCO staff and various intervenors filed a joint stipulation and settlement agreement with the PUCO. The agreement includes a $68 million annual decrease in base rates based on an ROE of 9.7%. The difference between OPCo’s requested annual base rate increase and the agreed upon decrease is primarily due to a reduction in the requested ROE, the removal of proposed future energy efficiency costs and a decrease in vegetation management expenses moved to recovery in riders. Additionally, the agreement includes: (a) an increased fixed monthly residential customer charge, (b) the discontinuation of rate decoupling and (c) the continuation of the DIR with annual revenue caps of $57 million in 2021, $91 million in 2022, $116 million in 2023 and $51 million for the first five months of 2024. Annual revenue caps for the DIR can be increased if OPCo achieves certain reliability standards. If the joint stipulation and settlement agreement is approved by the PUCO, new base rates will go into effect 14 days after such approval. A hearing is scheduled with the PUCO in May 2021. If the joint stipulation and settlement agreement is denied by the PUCO, it could reduce future net income and cash flows and impact financial condition.

2019 Ohio DIR Audit

OPCo conducts business under an ESP as approved by the PUCO which subjects the DIR to annual audits. In August 2020, a third-party consulting company filed an audit report with the PUCO indicating that OPCo exceeded its 2019 authorized revenue limit by $17 million. Management disagrees with the audit results and believes that OPCo was below its authorized revenue limit in 2019. The PUCO has not yet issued a procedural schedule to address the audit results. If the results of the audit are upheld by the PUCO and any refunds to customers or revenue reductions are ordered, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2012 Texas Base Rate Case

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~~March 2021, the Texas Supreme ~~Court.~~Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals. The Texas Supreme Court’s opinion agrees with the PUCT’s judgment affirming the prudence of the Turk Plant; however, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. Motions for rehearing were due April 12, 2021 and no party filed a timely motion.

As of March 31, ~~2020,~~2021, the net book value of Turk Plant was ~~$1.5~~$1.4 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.

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2016 Texas Base Rate Case

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.~~ROE. 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~~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,~~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.

Hurricane Laura

~~2018 Louisiana Formula Rate Filing~~

In ~~April 2018,~~August 2020, Hurricane Laura hit the coasts of Louisiana and Texas, causing power outages to more than 130,000 customers across SWEPCo’s service territories. Prior to Hurricane Laura, SWEPCo did not have a catastrophe reserve or automatic deferral authority within any of its jurisdictions. In October 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Laura. In October 2020, as part of the 2020 Texas Base Rate Case, SWEPCo requested deferral authority of incremental other operation and maintenance expenses. As of March 31, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $82 million ($79 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $31 million, all of which is related to the Louisiana jurisdiction. Management expects to request recovery of these storm costs, in addition to the Hurricane Delta and February 2021 winter storm costs, in a future filing. If any costs related to Hurricane Laura are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Hurricane Delta

In October 2020, Hurricane Delta hit the coast of Louisiana, causing power outages to more than 23,000 customers in SWEPCo’s Louisiana jurisdiction. In November 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Delta. As of March 31, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $17 million, which has been deferred as a regulatory asset. Also, management estimates that SWEPCo has incurred incremental capital expenditures of $3 million. Management expects to request recovery of these storm costs, in addition to the Hurricane Laura and February 2021 winter storm costs, in a future filing. If any costs related to Hurricane Delta are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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2020 Texas Base Rate Case

In October 2020, SWEPCo filed ~~its formula rate plan for test year 2017~~a request with the ~~LPSC. The filing included~~PUCT for 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$105 million annual increase in ~~the supplemental filing is primarily the~~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 ~~of the return of Excess ADIT benefits to customers.~~

~~In October 2018, the LPSC staff issued~~in 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’snet annual requested ~~annual~~base rate increase of ~~$18~~$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 requested recovery of the Texas jurisdictional share of the Dolet Hills Power Station of $45 million which is expected to be retired by the end of 2021. In March 2021, intervenor testimony was ~~implemented in August 2018, is overstated by $4 million and proposes~~filed supporting an annual ~~rate~~revenue increase ranging from $20 million to $70 million based upon an ROE of ~~$14 million. Additionally, the report recommends SWEPCo refund the excess over-collections associated with the $4~~9% to 9.15%. In April 2021, staff testimony was filed supporting a $45 million ~~difference for the period~~annual increase in base rates based upon an ROE 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 2020.9.22%. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2020 Louisiana Base Rate Case

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. The request 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) 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 and (b) includes $10 million annually to recover deferred other operation and maintenance expenses related to Hurricanes Laura and Delta. In April 2021, the LPSC approved SWEPCo’s request to remove the hurricane storm costs from the base rate case filing. Management expects to request recovery of the storm costs associated with Hurricanes Delta, Laura and the February 2021 winter storm in a separate filing. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the ~~2019~~2020 Annual Report should be read in conjunction with this report.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third-parties unless specified below.

Letters of Credit (Applies to AEP and AEP ~~Texas and OPCo)~~Texas)

Standby letters of credit are entered into with third-parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

AEP has a $4 billion and $1 billion revolving credit ~~facility~~facilities due in ~~June 2022,~~March 2026 and 2023, respectively, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of March 31, ~~2020,~~2021, no letters of credit were issued under the revolving credit facility.

Company Amount Maturity
(in millions)
AEP $ 241.2
April 2020 to March 2021
AEP Texas 2.2
July 2020
OPCo (a) 1.0
April 2021

~~(a)~~Company

Amount

Maturity

(in millions)

AEP

183.2

April ~~2020, the maturity date was extended from April 2020~~2021 to ~~April 2021.~~March 2022

AEP Texas

2.2

July 2021

Guarantees of Equity Method Investees (Applies to AEP)

In ~~April~~ 2019, AEP acquired Sempra Renewables LLC. ~~See “Acquisitions” section~~The transaction resulted in the acquisition of ~~Note 6~~a 50% ownership interest in five non-consolidated joint ventures and the acquisition of two tax equity partnerships. Parent has issued guarantees over the performance of the joint ventures. If a joint venture were to default on payments or performance, Parent would be required to make payments on behalf of the joint venture. As of March 31, 2021, the maximum potential amount of future payments associated with these guarantees was $157 million, with the last

guarantee expiring in December 2037. The non-contingent liability recorded associated with these guarantees was $30 million, with an additional $1 million expected credit loss liability for ~~additional information.~~the contingent portion of the guarantees. Management considered historical losses, economic conditions and reasonable and supportable forecasts in the calculation of the expected credit loss. As the joint ventures generate cash flows through PPAs, the measurement of the contingent portion of the guarantee liability is based upon assessments of the credit quality and default probabilities of the respective PPA counterparties.

Indemnifications and Other Guarantees

The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, ~~2020,~~2021, there were no material liabilities recorded for any indemnifications.

AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf. AEPSC also conducts power purchase-and-sale activity on behalf of PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf.

Master Lease Agreements (Applies to all Registrants except AEPTCo)

The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed. As of March 31, ~~2020,~~2021, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

Company
Maximum
Potential Loss
(in millions)
AEP $ 48.5
AEP Texas 11.6
APCo 6.6
I&M 4.3
OPCo 7.6
PSO 4.4
SWEPCo 4.9

Rockport Lease (Applies to AEP and I&M)

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.

The Owner Trustee owns the Plant and leases equal portions to AEGCo and I&M. The lease is accounted for as an operating ~~lease with the payment obligations included in the future minimum lease payments schedule earlier in this note.~~lease. The lease term is for 33 years and at the end of the lease term, AEGCo and I&M have the option to renew the lease at a rate that approximates fair value. ~~The option to~~In November 2020, management announced that AEP will not renew ~~was not included in the measurement of~~ the lease ~~obligation as of March 31, 2020 as the execution of the option was not reasonably certain.~~when it expires in 2022. AEP, AEGCo and I&M have no ownership interest in the Owner

Trustee and do not guarantee its debt.

The future minimum lease payments for this sale-and-leaseback transaction as of March 31, ~~2020~~2021 were as follows:

Future Minimum Lease Payments AEP (a) I&M
(in millions)
2020 $ 147.8
$ 73.9
2021 147.8
73.9
2022 147.5
73.7
Total Future Minimum Lease Payments $ 443.1
$ 221.5

AEPRO Boat and Barge Leases (Applies to AEP)

In 2015, AEP sold its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. Certain boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the respective lessors, ensuring future payments under such leases with maturities up to 2027. As of March 31, ~~2020,~~2021, the maximum potential amount of future payments required under the guaranteed leases was ~~$53~~$47 million. Under the terms of certain of the arrangements, upon the lessors exercising their rights after an event of default by the nonaffiliated party, AEP is entitled to enter into new lease arrangements as a lessee that would have substantially the same terms as the existing leases. Alternatively, for the arrangements with one of the lessors, upon an event of default by the nonaffiliated party and the lessor exercising its rights, payment to the lessor would allow AEP to step into the lessor’s rights as well as obtaining title to the assets. Under either situation, AEP would have the ability to utilize the assets in the normal course of barging operations. AEP would also have the right to sell the acquired assets for which it obtained title. As of March 31, ~~2020,~~2021, AEP’s boat and barge lease guarantee liability was $4$3 million, of which $1 million was recorded in Other Current Liabilities and $3$2 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance ~~sheet.~~sheets.

In February 2020, the nonaffiliated party filed Chapter 11 bankruptcy. The party entered into a restructuring support agreement and has announced it ~~expects~~expected to continue their operations as normal. In March 2020, the bankruptcy court approved the party’s recapitalization plan. In April 2020, the nonaffiliated party emerged from bankruptcy. Management has determined that it is reasonably possible that enforcement of AEP’s liability for future payments under these leases will be exercised within the next twelve months. In such an event, if AEP is unable to sell or incorporate any of the acquired assets into its fleet operations, it could reduce future net income and cash flows and impact financial condition.

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials. The Registrants currently incur costs to dispose of these substances safely. For remediation processes not specifically discussed, management does not anticipate that the liabilities, if any, arising from such remediation processes would have a material effect on the financial statements.

~~Virginia House Bill 443 (Applies to AEP and APCo)~~

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July 1, 2022. APCo is permitted to record carrying costs on the unrecovered balance of closure costs at a weighted average cost of capital approved by the Virginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered from Virginia jurisdictional customers through the E-RAC. Management does not expect HB 443 to materially impact results of operations or cash flows, but does anticipate a material impact to APCo’s balance sheet.

NUCLEAR CONTINGENCIES (Applies to AEP and I&M)

I&M owns and operates the Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

OPERATIONAL CONTINGENCIES

Rockport Plant Litigation (Applies to AEP and I&M)

AEGCo and I&M sought and were granted dismissal by the U.S. District Court for the Southern District of Ohio of certain of the plaintiffs’ claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. Plaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit.

Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. ~~As part~~The district court’s stay of the ~~modification to~~lease litigation expired in August 2020. Upon expiration of the stay, plaintiffs filed a motion for partial summary judgment, arguing that the consent decree ~~I&M agreed to provide an additional $7.5 million to citizens’ groups~~violates the facility lease and the ~~states for environmental mitigation projects. As joint owners in the Rockport Plant, the $7.5 million payment was shared between AEGCo~~participation agreement and I&M based on the joint ownership agreement. The district court entered a stay that expired in February 2020. Settlement negotiations are continuing, and the parties filed a joint proposed case schedule in February 2020. See “Modification of the New Source Review Litigation Consent Decree” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

~~Management will continue to defend against the claims. Given~~requesting that the district court ~~dismissed~~enter a judgment for the plaintiffs on their breach of contract claim. AEP’s memorandum in opposition to plaintiffs’ ~~claims seeking compensatory relief~~motion for partial summary judgment was filed in October 2020. At the parties’ request, the district court stayed the case until April 19, 2021 to provide the parties an opportunity to resolve the case.

On April 20, 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $115.5 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit, with closing to occur as ~~premature,~~of the end of the Rockport Plant, Unit 2 lease in December 2022. As a result, the parties have submitted a stipulation and ~~that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management cannot determine a range~~order of ~~potential losses that is reasonably possible of occurring.~~

~~Patent Infringement Complaint (Applies to AEP, AEP Texas and SWEPCo)~~

In July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs) filed a patent infringement complaint against various parties, including AEP Texas, AGR, Cardinal Operating Company and SWEPCo (collectively, the AEP Defendants). The complaint allegesdismissal requesting that the ~~AEP Defendants infringed two patents owned by~~district court dismiss the case without prejudice to plaintiffs ~~by using specific processes for mercury control at certain coal-fired generating stations.~~asserting their claims in a re-filed action or in a new action. The ~~complaint seeks injunctive relief~~agreement is subject to customary closing conditions, including regulatory approvals, and ~~damages.~~as of the closing will result in a final settlement of, and release of claims in, the lease litigation. Management ~~will continue to defend against~~believes its financial statements appropriately reflect the ~~claims. Management is unable to determine a range~~expected resolution of ~~potential losses that is reasonably possible of occurring.~~the pending litigation.

139

Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula

Litigation Related to Ohio House Bill 6 (HB 6)

140

6. ACQUISITIONS

The disclosures in this note apply to AEP unless indicated otherwise.

~~Sempra Renewables LLC~~Dry Lake Solar Project (Generation & Marketing Segment)

In ~~April 2019,~~November 2020, AEP ~~acquired Sempra Renewables LLC~~signed a Purchase and ~~its ownership interests in 724 MWs of wind generation and battery assets valued at approximately $1.1 billion. This acquisition is part of AEP’s strategy~~Sale Agreement with a nonaffiliate to ~~grow its renewable generation portfolio and to diversify generation resources. AEP paid $580 million in cash and acquired~~acquire a ~~50% ownership~~75% interest in ~~five non-consolidated joint ventures with net assets valued at $404~~the 100 MW Dry Lake Solar Project (Dry Lake) located in southern Nevada for approximately $114 million. In March 2021, AEP closed the transaction and the solar project is expected to be in-service in the second quarter of 2021. Approximately $103 million as of the ~~acquisition date (which includes $364 million~~purchase price was paid upon closing of ~~existing debt obligations). Additionally,~~ the transaction ~~included~~and the remaining $11 million will be paid when the project is placed in service. In accordance with the accounting guidance for “Business Combinations,” management determined that the acquisition of ~~two tax equity partnerships~~Dry Lake represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Dry Lake is a VIE and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact Dry Lake’s economic performance. As the primary beneficiary of Dry Lake, AEP consolidates Dry Lake into its financial statements. As a result, to account for the initial consolidation of Dry Lake, management applied the acquisition method by allocating the purchase price based on the relative fair value of the assets acquired and noncontrolling interest assumed. The fair value of the primary assets acquired and the ~~associated recognition of~~ noncontrolling ~~tax equity~~ interest ~~of $135 million.~~

assumed was determined using the market approach. The key input assumptions were the transaction price paid for AEP’s interest in Dry Lake and recent third-party market transactions for similar solar generation facilities. The nonaffiliated interest in Dry Lake is presented in Noncontrolling Interests on the balance sheets. Upon closing of the ~~purchase, Sempra Renewables LLC~~transaction, AEP recognized Property, Plant and Equipment of approximately $133 million, Noncontrolling Interest of approximately $19 million and Accounts Payable of approximately $11 million on the balance sheets.

Subsequent Event

North Central Wind Energy Facilities (Vertically Integrated Utilities Segment) (Applies to AEP, PSO and SWEPCo)

In 2020, PSO and SWEPCo received regulatory approvals to acquire the North Central Wind Energy Facilities, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. PSO will own 45.5% and SWEPCo will own 54.5% of North Central Wind Energy Facilities. In total, the three wind facilities will cost approximately $2 billion and consist of a 999 MW facility, a 287 MW facility and a 199 MW facility.The 199 MW wind facility was ~~legally renamed AEP Wind Holdings LLC. AEP Wind Holdings LLC develops, owns~~acquired and ~~operates, or holds interests~~placed in-service in ~~wind generation facilities~~April 2021. The estimated investment in the ~~United States. The operating~~199 MW wind generation portfolio includes seven wind farms. Five wind farms are jointly-owned with BP Wind Energy, and two wind farms are consolidated by AEP and are tax equity partnerships with nonaffiliated noncontrolling interests. All seven wind farms have long-term PPAs for 100% of their energy production.

Parent has issued guarantees over the performance of the joint ventures. If a joint venture were to default on payments or performance, Parent would be required to make payments on behalf of the joint venture. As of March 31, 2020, the maximum potential amount of future payments associated with these guarantees was $175 million, with the last guarantee expiring in December 2037. The non-contingent liability recorded associated with these guarantees was $33 million, with an additional $1 million expected credit loss liability for the contingent portion of the guarantees. Management considered historical losses, economic conditions, and reasonable and supportable forecasts in the calculation of the expected credit loss. As the joint ventures generate cash flows through PPAs, the measurement of the contingent portion of the guarantee liabilityfacility is ~~based upon assessments of the credit quality and default probabilities of the respective PPA counterparties.~~

$307 million.

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7. BENEFIT PLANS

The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.

AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees.

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans:

AEP


	Pension Plans				OPEB
	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2021		2020
	(in millions)
Service Cost	$	32.3	$	28.0	$	2.4	$	2.5
Interest Cost	34.3		42.0		7.6		9.9
Expected Return on Plan Assets	(57.5)		(66.2)		(22.8)		(23.9)
Amortization of Prior Service Credit	0		0		(17.7)		(17.4)
Amortization of Net Actuarial Loss	25.4		23.4		0		1.5
Net Periodic Benefit Cost (Credit)	$	34.5	$	27.2	$	(30.5)	$	(27.4)

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2020 2019 2020 2019
(in millions)
Service Cost $ 28.0
$ 23.9
$ 2.5
$ 2.4
Interest Cost 42.0
51.1
9.9
12.6
Expected Return on Plan Assets (66.2 ) (74.0 ) (23.9 ) (23.4 )
Amortization of Prior Service Credit —
—
(17.4 ) (17.3 )
Amortization of Net Actuarial Loss 23.4
14.4
1.5
5.5
Net Periodic Benefit Cost (Credit) $ 27.2
$ 15.4
$ (27.4 ) $ (20.2 )


	Pension Plans				OPEB
	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2021		2020
	(in millions)
Service Cost	$	3.0	$	2.6	$	0.2	$	0.2
Interest Cost	2.8		3.5		0.6		0.8
Expected Return on Plan Assets	(4.9)		(5.7)		(1.9)		(2.0)
Amortization of Prior Service Credit	0		0		(1.5)		(1.4)
Amortization of Net Actuarial Loss	2.1		1.9		0		0.1
Net Periodic Benefit Cost (Credit)	$	3.0	$	2.3	$	(2.6)	$	(2.3)

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2020 2019 2020 2019
(in millions)
Service Cost $ 2.6
$ 2.1
$ 0.2
$ 0.2
Interest Cost 3.5
4.4
0.8
1.0
Expected Return on Plan Assets (5.7 ) (6.4 ) (2.0 ) (2.0 )
Amortization of Prior Service Credit —
—
(1.4 ) (1.5 )
Amortization of Net Actuarial Loss 1.9
1.2
0.1
0.5
Net Periodic Benefit Cost (Credit) $ 2.3
$ 1.3
$ (2.3 ) $ (1.8 )


	Pension Plans				OPEB
	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2021		2020
	(in millions)
Service Cost	$	3.0	$	2.6	$	0.3	$	0.3
Interest Cost	4.1		5.1		1.2		1.6
Expected Return on Plan Assets	(7.3)		(8.4)		(3.4)		(3.6)
Amortization of Prior Service Credit	0		0		(2.6)		(2.5)
Amortization of Net Actuarial Loss	3.0		2.8		0		0.2
Net Periodic Benefit Cost (Credit)	$	2.8	$	2.1	$	(4.5)	$	(4.0)

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2020
2019 2020 2019
(in millions)
Service Cost $ 2.6
$ 2.4
$ 0.3
$ 0.3
Interest Cost 5.1
6.3
1.6
2.2
Expected Return on Plan Assets (8.4 ) (9.4 ) (3.6 ) (3.7 )
Amortization of Prior Service Credit —
—
(2.5 ) (2.5 )
Amortization of Net Actuarial Loss 2.8
1.8
0.2
0.9
Net Periodic Benefit Cost (Credit) $ 2.1
$ 1.1
$ (4.0 ) $ (2.8 )

142

I&M


	Pension Plans				OPEB
	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2021		2020
	(in millions)
Service Cost	$	4.4	$	3.9	$	0.3	$	0.3
Interest Cost	4.0		4.9		0.9		1.2
Expected Return on Plan Assets	(7.2)		(8.3)		(2.8)		(2.9)
Amortization of Prior Service Credit	0		0		(2.4)		(2.4)
Amortization of Net Actuarial Loss	2.9		2.7		0		0.2
Net Periodic Benefit Cost (Credit)	$	4.1	$	3.2	$	(4.0)	$	(3.6)

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2020 2019 2020 2019
(in millions)
Service Cost $ 3.9
$ 3.4
$ 0.3
$ 0.3
Interest Cost 4.9
6.0
1.2
1.5
Expected Return on Plan Assets (8.3 ) (9.2 ) (2.9 ) (2.8 )
Amortization of Prior Service Credit —
—
(2.4 ) (2.4 )
Amortization of Net Actuarial Loss 2.7
1.6
0.2
0.7
Net Periodic Benefit Cost (Credit) $ 3.2
$ 1.8
$ (3.6 ) $ (2.7 )

OPCo


	Pension Plans				OPEB
	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2021		2020
	(in millions)
Service Cost	$	2.9	$	2.4	$	0.2	$	0.2
Interest Cost	3.1		3.9		0.8		1.0
Expected Return on Plan Assets	(5.6)		(6.6)		(2.4)		(2.6)
Amortization of Prior Service Credit	0		0		(1.8)		(1.8)
Amortization of Net Actuarial Loss	2.2		2.1		0		0.2
Net Periodic Benefit Cost (Credit)	$	2.6	$	1.8	$	(3.2)	$	(3.0)

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2020 2019 2020 2019
(in millions)
Service Cost $ 2.4
$ 2.0
$ 0.2
$ 0.2
Interest Cost 3.9
4.7
1.0
1.4
Expected Return on Plan Assets (6.6 ) (7.3 ) (2.6 ) (2.7 )
Amortization of Prior Service Credit —
—
(1.8 ) (1.7 )
Amortization of Net Actuarial Loss 2.1
1.3
0.2
0.6
Net Periodic Benefit Cost (Credit) $ 1.8
$ 0.7
$ (3.0 ) $ (2.2 )

PSO


	Pension Plans				OPEB
	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2021		2020
	(in millions)
Service Cost	$	1.9	$	1.8	$	0.2	$	0.2
Interest Cost	1.7		2.1		0.4		0.5
Expected Return on Plan Assets	(3.1)		(3.6)		(1.3)		(1.3)
Amortization of Prior Service Credit	0		0		(1.1)		(1.1)
Amortization of Net Actuarial Loss	1.3		1.2		0		0.1
Net Periodic Benefit Cost (Credit)	$	1.8	$	1.5	$	(1.8)	$	(1.6)

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2020 2019 2020 2019
(in millions)
Service Cost $ 1.8
$ 1.6
$ 0.2
$ 0.2
Interest Cost 2.1
2.6
0.5
0.7
Expected Return on Plan Assets (3.6 ) (4.1 ) (1.3 ) (1.3 )
Amortization of Prior Service Credit —
—
(1.1 ) (1.1 )
Amortization of Net Actuarial Loss 1.2
0.8
0.1
0.3
Net Periodic Benefit Cost (Credit) $ 1.5
$ 0.9
$ (1.6 ) $ (1.2 )

Pension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,
2020 2019 2020 2019
(in millions)
Service Cost $ 2.5
$ 2.1
$ 0.2
$ 0.2
Interest Cost 2.5
3.1
0.6
0.8
Expected Return on Plan Assets (3.9 ) (4.4 ) (1.5 ) (1.5 )
Amortization of Prior Service Credit —
—
(1.3 ) (1.3 )
Amortization of Net Actuarial Loss 1.4
0.9
0.1
0.3
Net Periodic Benefit Cost (Credit) $ 2.5
$ 1.7
$ (1.9 ) $ (1.5 )

143

8. BUSINESS SEGMENTS

The disclosures in this note apply to all Registrants unless indicated otherwise.

AEP’s Reportable Segments

AEP’s reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

•Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

•Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.

•OPCo purchases energy and capacity to serve ~~SSO~~standard service offer customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

•Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved ROEs.

•Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ROEs.

Generation & Marketing

~~Competitive generation in ERCOT and PJM.~~

•Contracted renewable energy investments and management services.

•Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO.

•Competitive generation in PJM.

The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense, income tax expense and other nonallocated costs.

144

The tables below present AEP’s reportable segment income statement information for the three months ended March 31, ~~2020~~2021 and ~~2019~~2020 and reportable segment balance sheet information as of March 31, ~~2020~~2021 and December 31, ~~2019.~~2020.


	Three Months Ended March 31, 2021
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)		Reconciling Adjustments		Consolidated
	(in millions)
Revenues from:
External Customers	$	2,504.5	$	1,082.3	$	87.9	$	601.7	$	4.7	$	0	$	4,281.1
Other Operating Segments	32.8		5.8		289.1		32.5		8.2		(368.4)		0
Total Revenues	$	2,537.3	$	1,088.1	$	377.0	$	634.2	$	12.9	$	(368.4)	$	4,281.1



Net Income (Loss)	$	271.4	$	114.4	$	173.2	$	38.2	$	(18.4)	$	0	$	578.8

	Three Months Ended March 31, 2020
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)		Reconciling Adjustments		Consolidated
	(in millions)
Revenues from:
External Customers	$	2,193.0	$	1,075.2	$	73.1	$	408.4	$	(2.2)	$	0	$	3,747.5
Other Operating Segments	33.7		31.7		237.1		30.2		22.1		(354.8)		0
Total Revenues	$	2,226.7	$	1,106.9	$	310.2	$	438.6	$	19.9	$	(354.8)	$	3,747.5



Net Income (Loss)	$	246.3	$	116.2	$	141.6	$	30.5	$	(35.3)	$	0	$	499.3

145

Three Months Ended March 31, 2020
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:

External Customers $ 2,193.0
$ 1,075.2
$ 73.1
$ 408.4
$ (2.2 ) $ —
$ 3,747.5
Other Operating Segments 33.7
31.7
237.1
30.2
22.1
(354.8 ) —
Total Revenues $ 2,226.7
$ 1,106.9
$ 310.2
$ 438.6
$ 19.9
$ (354.8 ) $ 3,747.5

Net Income (Loss) $ 246.3
$ 116.2
$ 141.6
$ 30.5
$ (35.3 ) $ —
$ 499.3

Three Months Ended March 31, 2019
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:

External Customers $ 2,372.3
$ 1,179.8
$ 61.2
$ 439.7
$ 3.8
$ —
$ 4,056.8
Other Operating Segments 31.0
42.2
195.2
42.1
21.7
(332.2 ) —
Total Revenues $ 2,403.3
$ 1,222.0
$ 256.4
$ 481.8
$ 25.5
$ (332.2 ) $ 4,056.8

Net Income (Loss) $ 303.6
$ 156.5
$ 125.2
$ 39.2
$ (50.4 ) $ —
$ 574.1


	March 31, 2021
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)			Reconciling Adjustments			Consolidated
	(in millions)
Total Property, Plant and Equipment	$	49,448.9	$	21,492.9	$	12,185.2	$	2,080.6	$	405.3		$	0		$	85,612.9
Accumulated Depreciation and Amortization	15,950.1		3,951.3		648.1		183.8		183.5			0			20,916.8
Total Property Plant and Equipment - Net	$	33,498.8	$	17,541.6	$	11,537.1	$	1,896.8	$	221.8		$	0		$	64,696.1


Total Assets	$	44,591.3	$	20,076.9	$	12,925.8	$	3,881.8	$	6,072.0	(b)	$	(4,562.7)	(c)	$	82,985.1

Long-term Debt Due Within One Year:

Nonaffiliated	$	1,078.3	$	589.0	$	52.4	$	0	$	410.5	(d)	$	0		$	2,130.2

Long-term Debt:
Affiliated	65.0		0		0		0		0			(65.0)			0
Nonaffiliated	13,185.8		7,097.4		4,089.7		0		5,841.9		(d)	0			30,214.8

Total Long-term Debt	$	14,329.1	$	7,686.4	$	4,142.1	$	0	$	6,252.4	(d)	$	(65.0)		$	32,345.0



	December 31, 2020
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)			Reconciling Adjustments			Consolidated
	(in millions)
Total Property, Plant and Equipment	$	49,023.3	$	21,145.0	$	11,827.2	$	1,910.2	$	407.3		$	0		$	84,313.0
Accumulated Depreciation and Amortization	15,586.2		3,879.3		595.7		166.1		184.1			0			20,411.4
Total Property Plant and Equipment - Net	$	33,437.1	$	17,265.7	$	11,231.5	$	1,744.1	$	223.2		$	0		$	63,901.6



Total Assets	$	42,752.7	$	19,765.9	$	12,627.3	$	3,585.9	$	5,987.1	(b)	$	(3,961.7)	(c)	$	80,757.2

Long-term Debt Due Within One Year:

Nonaffiliated	$	1,034.6	$	588.8	$	52.3	$	0	$	410.4	(d)	$	0		$	2,086.1

Long-term Debt:
Affiliated	65.0		0		0		0		0			(65.0)			0
Nonaffiliated	12,375.6		6,661.9		4,075.7		0		5,873.2		(d)	0			28,986.4

Total Long-term Debt	$	13,475.2	$	7,250.7	$	4,128.0	$	0	$	6,283.6	(d)	$	(65.0)		$	31,072.5

March 31, 2020
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing Corporate and Other (a) Reconciling
Adjustments Consolidated
(in millions)
Total Property, Plant and Equipment $ 47,764.3
$ 20,182.8
$ 10,662.9
$ 1,753.2
$ 408.3
$ (354.5 ) (b) $ 80,417.0
Accumulated Depreciation and Amortization 14,821.8
3,964.6
464.0
116.9
187.3
(186.5 ) (b) 19,368.1
Total Property Plant and Equipment - Net $ 32,942.5
$ 16,218.2
$ 10,198.9
$ 1,636.3
$ 221.0
$ (168.0 ) (b) $ 61,048.9

Total Assets $ 41,020.5
$ 18,892.5
$ 11,484.8
$ 3,216.4
$ 7,033.6
(c) $ (3,923.8 ) (b) (d) $ 77,724.0

Long-term Debt Due Within One Year:
Affiliated $ 20.0
$ —
$ —
$ —
$ —
$ (20.0 ) $ —
Nonaffiliated 1,316.3
289.0
—
—
504.4
(e) —
2,109.7

Long-term Debt:
Affiliated 39.0
—
—
—
—
(39.0 ) —
Nonaffiliated 11,641.0
6,585.5
3,600.3
—
3,956.2
(e)

—
25,783.0

Total Long-term Debt $ 13,016.3
$ 6,874.5
$ 3,600.3
$ —
$ 4,460.6
$ (59.0 ) $ 27,892.7
(a)Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and other nonallocated costs.

(b)Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.

December 31, 2019
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing Corporate and Other (a) Reconciling
Adjustments Consolidated
(in millions)
Total Property, Plant and Equipment $ 47,323.7
$ 19,773.3
$ 10,334.0
$ 1,650.8
$ 418.4
$ (354.5 ) (b) $ 79,145.7
Accumulated Depreciation and Amortization 14,580.4
3,911.2
418.9
99.0
184.5
(186.4 ) (b) 19,007.6
Total Property Plant and Equipment - Net $ 32,743.3
$ 15,862.1
$ 9,915.1
$ 1,551.8
$ 233.9
$ (168.1 ) (b) $ 60,138.1

Total Assets $ 41,228.8
$ 18,757.5
$ 11,143.5
$ 3,123.8
$ 5,440.0
(c) $ (3,801.3 ) (b) (d) $ 75,892.3

Long-term Debt Due Within One Year:
Affiliated $ 20.0
$ —
$ —
$ —
$ —
$ (20.0 ) $ —
Nonaffiliated 704.7
392.2
—
—
501.8
(e) —
1,598.7

Long-term Debt:
Affiliated 39.0
—
—
—
—
(39.0 ) —
Nonaffiliated 12,162.0
6,248.1
3,593.8
—
3,122.9
(e) —
25,126.8

Total Long-term Debt $ 12,925.7
$ 6,640.3
$ 3,593.8
$ —
$ 3,624.7
$ (59.0 ) $ 26,725.5
(c)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.

(d)Amounts are inclusive of the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information.


~~(a)~~	Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and other nonallocated costs.


~~(b)~~	~~Includes eliminations due to an intercompany finance lease.~~


~~(c)~~	~~Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.~~


~~(d)~~	~~Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.~~


~~(e)~~	~~Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information.~~

Registrant Subsidiaries’ Reportable Segments (Applies to all Registrant Subsidiaries except AEPTCo)

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an integrated electricity transmission and distribution business for AEP Texas and OPCo. Other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

146

AEPTCo’s Reportable Segments

AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities. The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems.

AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. The State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities.

The tables below present AEPTCo’s reportable segment income statement information for the three months ended March 31, ~~2020~~2021 and ~~2019~~2020 and reportable segment balance sheet information as of March 31, ~~2020~~2021 and December 31, ~~2019.~~2020.


	Three Months Ended March 31, 2021
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	76.0	$	0		$	0		$	76.0
Sales to AEP Affiliates	285.6		0			0			285.6
Other Revenues	0.1		0			0			0.1
Total Revenues	$	361.7	$	0		$	0		$	361.7

Interest Income	$	0	$	38.3		$	(38.2)	(a)	$	0.1
Interest Expense	34.1		38.2			(38.2)		(a)	34.1
Income Tax Expense	39.6		0			0			39.6


Net Income	$	151.7	$	0	(b)	$	0		$	151.7

	Three Months Ended March 31, 2020
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	61.3	$	0		$	0		$	61.3
Sales to AEP Affiliates	233.7		0			0			233.7
Other Revenues	0.6		0			0			0.6
Total Revenues	$	295.6	$	0		$	0		$	295.6

Interest Income	$	0.2	$	34.0		$	(33.4)	(a)	$	0.8
Interest Expense	29.6		33.4			(33.4)		(a)	29.6
Income Tax Expense	31.8		0			0			31.8


Net Income	$	117.3	$	0.5	(b)	$	0		$	117.8

147

Three Months Ended March 31, 2020
State Transcos AEPTCo Parent Reconciling Adjustments
AEPTCo
Consolidated
(in millions)
Revenues from:
External Customers $ 61.3
$ —
$ —
$ 61.3
Sales to AEP Affiliates 233.7
—
—
233.7
Other Revenues 0.6
—
—
0.6
Total Revenues $ 295.6
$ —
$ —
$ 295.6

Interest Income $ 0.2
$ 34.0
$ (33.4 ) (a) $ 0.8
Interest Expense 29.6
33.4
(33.4 ) (a) 29.6
Income Tax Expense 31.8
—
—
31.8

Net Income $ 117.3
$ 0.5
(b) $ —
$ 117.8

Three Months Ended March 31, 2019
State Transcos AEPTCo Parent Reconciling Adjustments
AEPTCo
Consolidated
(in millions)
Revenues from:
External Customers $ 50.3
$ —
$ —
$ 50.3
Sales to AEP Affiliates 193.2
—
—
193.2
Total Revenues $ 243.5
$ —
$ —
$ 243.5

Interest Income $ 0.2
$ 28.4
$ (27.9 ) (a) $ 0.7
Interest Expense 21.7
27.9
(27.9 ) (a) 21.7
Income Tax Expense 27.6
—
—
27.6

Net Income $ 104.2
$ 0.1
(b) $ —
$ 104.3


































	March 31, 2021
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Total Transmission Property	$	11,694.0	$	0		$	0		$	11,694.0
Accumulated Depreciation and Amortization	623.6		0			0			623.6
Total Transmission Property – Net	$	11,070.4	$	0		$	0		$	11,070.4

Notes Receivable - Affiliated	$	0	$	3,899.0		$	(3,899.0)	(c)	$	0

Total Assets	$	11,458.3	$	4,107.2	(d)	$	(4,050.4)	(e)	$	11,515.1

Total Long-term Debt	$	3,990.0	$	3,949.0		$	(3,990.0)	(c)	$	3,949.0

	December 31, 2020
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Total Transmission Property	$	11,345.6	$	0		$	0		$	11,345.6
Accumulated Depreciation and Amortization	572.8		0			0			572.8
Total Transmission Property – Net	$	10,772.8	$	0		$	0		$	10,772.8

Notes Receivable - Affiliated	$	0	$	3,948.5		$	(3,948.5)	(c)	$	0

Total Assets	$	11,185.1	$	4,084.0	(d)	$	(4,023.1)	(e)	$	11,246.0

Total Long-term Debt	$	3,990.0	$	3,948.5		$	(3,990.0)	(c)	$	3,948.5

(a)Elimination of intercompany interest income/interest expense on affiliated debt arrangement.

(b)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.

(c)Elimination of intercompany debt.

(d)Includes the elimination of AEPTCo Parent’s investments in State Transcos.

(e)Primarily relates to the elimination of Notes Receivable from the State Transcos.

148

March 31, 2020
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Total Transmission Property $ 10,221.2
$ —
$ —
$ 10,221.2
Accumulated Depreciation and Amortization 445.8
—
—
445.8
Total Transmission Property – Net $ 9,775.4
$ —
$ —
$ 9,775.4

Notes Receivable - Affiliated $ —
$ 3,427.8
$ (3,427.8 ) (c) $ —

Total Assets $ 10,150.9
$ 3,562.7
(d) $ (3,513.7 ) (e) $ 10,199.9

Total Long-term Debt $ 3,465.0
$ 3,427.8
$ (3,465.0 ) (c) $ 3,427.8

December 31, 2019
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Total Transmission Property $ 9,893.2
$ —
$ —
$ 9,893.2
Accumulated Depreciation and Amortization 402.3
—
—
402.3
Total Transmission Property – Net $ 9,490.9
$ —
$ —
$ 9,490.9

Notes Receivable - Affiliated $ —
$ 3,427.3
$ (3,427.3 ) (c) $ —

Total Assets $ 9,865.0
$ 3,519.1
(d) $ (3,493.3 ) (e) $ 9,890.8

Total Long-term Debt $ 3,465.0
$ 3,427.3
$ (3,465.0 ) (c) $ 3,427.3


~~(a)~~	~~Elimination of intercompany interest income/interest expense on affiliated debt arrangement.~~


~~(b)~~	~~Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.~~


~~(c)~~	~~Elimination of intercompany debt.~~


~~(d)~~	~~Includes the elimination of AEPTCo Parent’s investments in State Transcos.~~


~~(e)~~	~~Primarily relates to the elimination of Notes Receivable from the State Transcos.~~

9. DERIVATIVES AND HEDGING

The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity.

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.

The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.

149

The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts:

Notional Volume of Derivative Instruments

March 31, ~~2020~~2021

Primary Risk
Exposure

Unit of
Measure
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Commodity:

Power MWhs 305.4
—
38.7
18.5
3.2
5.9
1.7
Natural Gas MMBtus 42.3
—
—
—
—
—
10.7
Heating Oil and Gasoline Gallons 5.0
1.3
0.8
0.5
1.0
0.5
0.7
Interest Rate USD $ 137.1
$ —
$ —
$ —
$ —
$ —
$ —

Interest Rate on Long-term Debt USD $ 650.0
$ —
$ 150.0
$ —
$ —
$ —
$ —


Primary Risk Exposure	Unit of Measure	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
		(in millions)
Commodity:
Power	MWhs	271.2		0		23.3		10.8		2.9		3.8		1.6

Natural Gas	MMBtus	22.7		0		0		0		0		0		7.0
Heating Oil and Gasoline	Gallons	5.0		1.3		0.8		0.5		1.0		0.5		0.7
Interest Rate	USD	$	123.6	$	0	$	0	$	0	$	0	$	0	$	0

Interest Rate on Long-term Debt	USD	$	950.0	$	0	$	0	$	0	$	0	$	0	$	0

December 31, ~~2019~~2020


Primary Risk Exposure	Unit of Measure	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
		(in millions)
Commodity:
Power	MWhs	331.3		0		46.9		19.7		3.0		11.9		4.0

Natural Gas	MMBtus	26.9		0		0		0		0		0		7.9
Heating Oil and Gasoline	Gallons	6.9		1.8		1.1		0.6		1.4		0.7		0.9
Interest Rate	USD	$	129.8	$	0	$	0	$	0	$	0	$	0	$	0

Interest Rate on Long-term Debt	USD	$	1,150.0	$	0	$	200.0	$	0	$	0	$	0	$	0

Primary Risk
Exposure

Unit of
Measure
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Commodity:

Power MWhs 365.9
—
61.0
26.8
7.1
14.9
4.4
Natural Gas MMBtus 40.7
—
—
—
—
—
11.6
Heating Oil and Gasoline Gallons 6.9
1.8
1.1
0.6
1.4
0.7
0.9
Interest Rate USD $ 140.1
$ —
$ —
$ —
$ —
$ —
$ —

Interest Rate on Long-term Debt USD $ 625.0
$ —
$ —
$ —
$ —
$ —
$ —

Fair Value Hedging Strategies (Applies to AEP)

Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating-rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges.

Cash Flow Hedging Strategies

The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk.

The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes ~~supply~~ and ~~demand market data and~~other assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $0$3 million and $5$3 million as of March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of ~~$76~~$8 million and ~~$39~~$7 million as of March 31, ~~2020~~2021 and December 31, ~~2019, respectively. APCo netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $5 million and $1 million as of March 31,~~ 2020, ~~and December 31, 2019,~~ respectively. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third-parties against short-term and long-term risk management liabilities were immaterial for the ~~other~~ Registrant Subsidiaries as of March 31, ~~2020~~2021 and December 31, ~~2019.~~2020.

The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets:

~~Fair Value of Derivative Instruments~~

152

Risk
Management
Contracts Hedging Contracts Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized Gross
Amounts
Offset in the
Statement of
Financial
Position (b) Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a)
(in millions)
Current Risk Management Assets $ 412.7
$ 13.5
$ 4.6
$ 430.8
$ (300.4 ) $ 130.4
Long-term Risk Management Assets 331.6
13.5
52.7
397.8
(74.1 ) 323.7
Total Assets 744.3
27.0
57.3
828.6
(374.5 ) 454.1

Current Risk Management Liabilities 401.7
103.2
5.3
510.2
(353.4 ) 156.8
Long-term Risk Management Liabilities 305.9
82.9
—
388.8
(96.9 ) 291.9
Total Liabilities 707.6
186.1
5.3
899.0
(450.3 ) 448.7

Total MTM Derivative Contract Net Assets (Liabilities) $ 36.7
$ (159.1 ) $ 52.0
$ (70.4 ) $ 75.8
$ 5.4

~~December 31, 2019~~

Risk
Management
Contracts Hedging Contracts Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized Gross
Amounts
Offset in the
Statement of
Financial
Position (b) Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a)
(in millions)
Current Risk Management Assets $ 513.9
$ 11.5
$ 6.5
$ 531.9
$ (359.1 ) $ 172.8
Long-term Risk Management Assets 290.8
11.0
12.6
314.4
(47.8 ) 266.6
Total Assets 804.7
22.5
19.1
846.3
(406.9 ) 439.4

Current Risk Management Liabilities 424.5
72.3
—
496.8
(382.5 ) 114.3
Long-term Risk Management Liabilities 244.5
75.7
—
320.2
(58.4 ) 261.8
Total Liabilities 669.0
148.0
—
817.0
(440.9 ) 376.1

Total MTM Derivative Contract Net Assets (Liabilities) $ 135.7
$ (125.5 ) $ 19.1
$ 29.3
$ 34.0
$ 63.3

AEP Texas

~~Fair Value of Derivative Instruments~~


	March 31, 2021
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Current Risk Management Assets	$	0.8	$	(0.8)	$	0
Long-term Risk Management Assets	0		0		0
Total Assets	0.8		(0.8)		0

Current Risk Management Liabilities	0		0		0
Long-term Risk Management Liabilities	0		0		0
Total Liabilities	0		0		0

Total MTM Derivative Contract Net Assets (Liabilities)	$	0.8	$	(0.8)	$	0

~~March 31, 2020~~


	December 31, 2020
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Current Risk Management Assets	$	0.4	$	(0.4)	$	0
Long-term Risk Management Assets	0		0		0
Total Assets	0.4		(0.4)		0

Current Risk Management Liabilities	0		0		0
Long-term Risk Management Liabilities	0		0		0
Total Liabilities	0		0		0

Total MTM Derivative Contract Net Assets (Liabilities)	$	0.4	$	(0.4)	$	0

153

Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ —
$ —
$ —
Long-term Risk Management Assets —
—
—
Total Assets —
—
—

Current Risk Management Liabilities 1.2
(1.2 ) —
Long-term Risk Management Liabilities —
—
—
Total Liabilities 1.2
(1.2 ) —

Total MTM Derivative Contract Net Assets (Liabilities) $ (1.2 ) $ 1.2
$ —

~~December 31, 2019~~

~~Risk Management~~

~~Gross Amounts Offset~~

~~Net Amounts of Assets/Liabilities~~

~~Contracts –~~

~~in the Statement of~~

~~Presented in the Statement of~~

~~Balance Sheet Location~~

~~Commodity (a)~~

~~Financial Position (b)~~

~~Financial Position (c)~~

~~(in millions)~~

~~Current Risk Management Assets~~

—

~~Long-term Risk Management Assets~~

—

~~Total Assets~~

—

~~Current Risk Management Liabilities~~

—

~~Long-term Risk Management Liabilities~~

—

~~Total Liabilities~~

—

~~Total MTM Derivative Contract Net Assets~~

—

APCo

~~Fair Value of Derivative Instruments~~


	March 31, 2021


	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement
Balance Sheet Location	Commodity (a)		Financial Position (b)		of Financial Position (c)
	(in millions)
Current Risk Management Assets	$	16.5	$	(9.6)	$	6.9
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets	0.5		(0.5)		0
Total Assets	17.0		(10.1)		6.9

Other Current Liabilities - Current Risk Management Liabilities	9.3		(9.1)		0.2
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities	0.5		(0.5)		0
Total Liabilities	9.8		(9.6)		0.2

Total MTM Derivative Contract Net Assets (Liabilities)	$	7.2	$	(0.5)	$	6.7

~~March 31, 2020~~

Risk Management Hedging Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts – Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Interest Rate (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 71.1
$ 0.3
$ (53.3 ) $ 18.1
Long-term Risk Management Assets 3.5
—
(3.4 ) 0.1
Total Assets 74.6
0.3
(56.7 ) 18.2

Current Risk Management Liabilities 68.3
5.3
(58.6 ) 15.0
Long-term Risk Management Liabilities 3.5
—
(3.4 ) 0.1
Total Liabilities 71.8
5.3
(62.0 ) 15.1

Total MTM Derivative Contract Net Assets (Liabilities) $ 2.8
$ (5.0 ) $ 5.3
$ 3.1

~~December 31, 2019~~

Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 124.4
$ (85.0 ) $ 39.4
Long-term Risk Management Assets 0.9
(0.8 ) 0.1
Total Assets 125.3
(85.8 ) 39.5

Current Risk Management Liabilities 86.2
(84.3 ) 1.9
Long-term Risk Management Liabilities 0.7
(0.7 ) —
Total Liabilities 86.9
(85.0 ) 1.9

Total MTM Derivative Contract Net Assets (Liabilities) $ 38.4
$ (0.8 ) $ 37.6


	December 31, 2020
					Gross Amounts
	Risk				of Risk		Gross Amounts		Net Amounts of Assets/
	Management		Hedging		Management		Offset in the		Liabilities Presented in
	Contracts –		Contracts –		Assets/Liabilities		Statement of		the Statement of
Balance Sheet Location	Commodity (a)		Interest Rate (a)		Recognized		Financial Position (b)		Financial Position (c)
	(in millions)
Current Risk Management Assets	$	38.8	$	2.4	$	41.2	$	(18.8)	$	22.4
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets	0.7		0		0.7		(0.6)		0.1
Total Assets	39.5		2.4		41.9		(19.4)		22.5

Other Current Liabilities - Current Risk Management Liabilities	19.7		3.4		23.1		(18.5)		4.6
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities	0.6		0		0.6		(0.5)		0.1
Total Liabilities	20.3		3.4		23.7		(19.0)		4.7

Total MTM Derivative Contract Net Assets (Liabilities)	$	19.2	$	(1.0)	$	18.2	$	(0.4)	$	17.8

154

I&M

~~Fair Value of Derivative Instruments~~


	March 31, 2021
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Current Risk Management Assets	$	6.8	$	(5.9)	$	0.9
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets	0.3		(0.3)		0
Total Assets	7.1		(6.2)		0.9

Other Current Liabilities - Current Risk Management Liabilities	6.2		(6.0)		0.2
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities	0.3		(0.3)		0
Total Liabilities	6.5		(6.3)		0.2

Total MTM Derivative Contract Net Assets	$	0.6	$	0.1	$	0.7

~~March 31, 2020~~


	December 31, 2020
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Current Risk Management Assets	$	17.2	$	(13.6)	$	3.6
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets	0.5		(0.4)		0.1
Total Assets	17.7		(14.0)		3.7

Other Current Liabilities - Current Risk Management Liabilities	12.1		(12.0)		0.1
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities	0.4		(0.3)		0.1
Total Liabilities	12.5		(12.3)		0.2

Total MTM Derivative Contract Net Assets (Liabilities)	$	5.2	$	(1.7)	$	3.5

Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 42.3
$ (35.6 ) $ 6.7
Long-term Risk Management Assets 2.1
(2.0 ) 0.1
Total Assets 44.4
(37.6 ) 6.8

Current Risk Management Liabilities 38.3
(36.6 ) 1.7
Long-term Risk Management Liabilities 2.1
(2.0 ) 0.1
Total Liabilities 40.4
(38.6 ) 1.8

Total MTM Derivative Contract Net Assets $ 4.0
$ 1.0
$ 5.0

~~December 31, 2019~~

Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 66.9
$ (57.1 ) $ 9.8
Long-term Risk Management Assets 0.5
(0.4 ) 0.1
Total Assets 67.4
(57.5 ) 9.9

Current Risk Management Liabilities 55.2
(54.7 ) 0.5
Long-term Risk Management Liabilities 0.4
(0.4 ) —
Total Liabilities 55.6
(55.1 ) 0.5

Total MTM Derivative Contract Net Assets (Liabilities) $ 11.8
$ (2.4 ) $ 9.4

OPCo

~~Fair Value of Derivative Instruments~~


	March 31, 2021
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Current Risk Management Assets	$	0.6	$	(0.6)	$	0
Long-term Risk Management Assets	0		0		0
Total Assets	0.6		(0.6)		0

Current Risk Management Liabilities	8.1		0		8.1
Long-term Risk Management Liabilities	95.9		0		95.9
Total Liabilities	104.0		0		104.0

Total MTM Derivative Contract Net Liabilities	$	(103.4)	$	(0.6)	$	(104.0)

~~March 31, 2020~~

Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ —
$ —
$ —
Long-term Risk Management Assets —
—
—
Total Assets —
—
—

Current Risk Management Liabilities 9.6
(0.9 ) 8.7
Long-term Risk Management Liabilities 112.2
—
112.2
Total Liabilities 121.8
(0.9 ) 120.9

Total MTM Derivative Contract Net Assets (Liabilities) $ (121.8 ) $ 0.9
$ (120.9 )

~~December 31, 2019~~

Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ —
$ —
$ —
Long-term Risk Management Assets —
—
—
Total Assets —
—
—

Current Risk Management Liabilities 7.3
—
7.3
Long-term Risk Management Liabilities 96.3
—
96.3
Total Liabilities 103.6
—
103.6

Total MTM Derivative Contract Net Liabilities $ (103.6 ) $ —
$ (103.6 )


	December 31, 2020
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Current Risk Management Assets	$	0.3	$	(0.3)	$	0
Long-term Risk Management Assets	0		0		0
Total Assets	0.3		(0.3)		0

Current Risk Management Liabilities	8.7		0		8.7
Long-term Risk Management Liabilities	101.6		0		101.6
Total Liabilities	110.3		0		110.3

Total MTM Derivative Contract Net Liabilities	$	(110.0)	$	(0.3)	$	(110.3)

155

PSO

~~Fair Value of Derivative Instruments~~


	March 31, 2021
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Current Risk Management Assets	$	5.8	$	(0.3)	$	5.5
Long-term Risk Management Assets	0		0		0
Total Assets	5.8		(0.3)		5.5

Current Risk Management Liabilities	0		0		0
Long-term Risk Management Liabilities	0		0		0
Total Liabilities	0		0		0

Total MTM Derivative Contract Net Assets (Liabilities)	$	5.8	$	(0.3)	$	5.5

~~March 31, 2020~~


	December 31, 2020
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Current Risk Management Assets	$	10.5	$	(0.2)	$	10.3
Long-term Risk Management Assets	0		0		0
Total Assets	10.5		(0.2)		10.3

Current Risk Management Liabilities	0		0		0
Long-term Risk Management Liabilities	0		0		0
Total Liabilities	0		0		0

Total MTM Derivative Contract Net Assets (Liabilities)	$	10.5	$	(0.2)	$	10.3

Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 6.7
$ (0.3 ) $ 6.4
Long-term Risk Management Assets —
—
—
Total Assets 6.7
(0.3 ) 6.4

Current Risk Management Liabilities 0.9
(0.8 ) 0.1
Long-term Risk Management Liabilities —
—
—
Total Liabilities 0.9
(0.8 ) 0.1

Total MTM Derivative Contract Net Assets $ 5.8
$ 0.5
$ 6.3

~~December 31, 2019~~

Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 16.3
$ (0.5 ) $ 15.8
Long-term Risk Management Assets —
—
—
Total Assets 16.3
(0.5 ) 15.8

Current Risk Management Liabilities 0.5
(0.5 ) —
Long-term Risk Management Liabilities —
—
—
Total Liabilities 0.5
(0.5 ) —

Total MTM Derivative Contract Net Assets $ 15.8
$ —
$ 15.8

SWEPCo

~~Fair Value~~


	March 31, 2021
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Current Risk Management Assets	$	1.7	$	(0.4)	$	1.3
Long-term Risk Management Assets	0		0		0
Total Assets	1.7		(0.4)		1.3

Current Risk Management Liabilities	0		0		0
Long-term Risk Management Liabilities	0.9		0		0.9
Total Liabilities	0.9		0		0.9

Total MTM Derivative Contract Net Assets (Liabilities)	$	0.8	$	(0.4)	$	0.4


	December 31, 2020
	Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of		Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)		Financial Position (c)
	(in millions)
Current Risk Management Assets	$	3.4	$	(0.2)	$	3.2
Long-term Risk Management Assets	0		0		0
Total Assets	3.4		(0.2)		3.2

Current Risk Management Liabilities	0.7		0		0.7
Long-term Risk Management Liabilities	1.0		0		1.0
Total Liabilities	1.7		0		1.7

Total MTM Derivative Contract Net Assets (Liabilities)	$	1.7	$	(0.2)	$	1.5

(a)Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”

(b)Amounts include counterparty netting of ~~Derivative Instruments~~risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”

~~March 31, 2020~~(c)All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.

156

Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 2.7
$ (0.1 ) $ 2.6
Long-term Risk Management Assets —
—
—
Total Assets 2.7
(0.1 ) 2.6

Current Risk Management Liabilities 2.9
(0.7 ) 2.2
Long-term Risk Management Liabilities 2.9
—
2.9
Total Liabilities 5.8
(0.7 ) 5.1

Total MTM Derivative Contract Net Assets (Liabilities) $ (3.1 ) $ 0.6
$ (2.5 )

~~December 31, 2019~~

Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 6.5
$ (0.1 ) $ 6.4
Long-term Risk Management Assets —
—
—
Total Assets 6.5
(0.1 ) 6.4

Current Risk Management Liabilities 2.0
(0.1 ) 1.9
Long-term Risk Management Liabilities 3.1
—
3.1
Total Liabilities 5.1
(0.1 ) 5.0

Total MTM Derivative Contract Net Assets $ 1.4
$ —
$ 1.4


~~(a)~~	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”


~~(b)~~	~~Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”~~


~~(c)~~	~~All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.~~

The tables below present the Registrants’ ~~activity~~amount of ~~derivative~~gain (loss) recognized on risk management contracts:

Amount of Gain (Loss) Recognized on

Risk Management Contracts

~~Three Months Ended March 31, 2020~~


	Three Months Ended March 31, 2021
Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	0.2	$	0	$	0	$	0	$	0	$	0	$	0

Generation & Marketing Revenues	(0.4)		0		0		0		0		0		0
Electric Generation, Transmission and Distribution Revenues	0		0		0.2		0		0		0		0


Purchased Electricity for Resale	0.4		0		0.4		0		0		0		0
Other Operation	0.3		0.1		0		0		0.1		0		0
Maintenance	0.5		0.1		0.1		0.1		0.1		0.1		0.1
Regulatory Assets (a)	6.4		0		0		(0.9)		6.6		0		0.8
Regulatory Liabilities (a)	22.0		0.4		3.4		(3.2)		2.9		11.2		6.2
Total Gain (Loss) on Risk Management Contracts	$	29.4	$	0.6	$	4.1	$	(4.0)	$	9.7	$	11.3	$	7.1

Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ 0.4
$ —
$ —
$ —
$ —
$ —
$ —
Generation & Marketing Revenues (10.3 ) —
—
—
—
—
—
Electric Generation, Transmission and Distribution Revenues —
—
0.2
0.1
—
—
—
Purchased Electricity for Resale 0.1
—
0.1
—
—
—
—
Other Operation (0.2 ) (0.1 ) —
—
(0.1 ) —
—
Maintenance (0.2 ) (0.1 ) (0.1 ) —
—
—
—
Regulatory Assets (a) (33.9 ) (1.2 ) (8.9 ) (0.7 ) (18.4 ) (0.5 ) (2.0 )
Regulatory Liabilities (a) 11.2
—
(7.3 ) 3.2
3.5
8.1
3.3
Total Gain (Loss) on Risk Management Contracts $ (32.9 ) $ (1.4 ) $ (16.0 ) $ 2.6
$ (15.0 ) $ 7.6
$ 1.3

~~Three Months Ended March 31, 2019~~

Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ 0.3
$ —
$ —
$ —
$ —
$ —
$ —
Generation & Marketing Revenues 2.7
—
—
—
—
—
—
Electric Generation, Transmission and Distribution Revenues —
—
(0.1 ) 0.3
—
—
0.1
Purchased Electricity for Resale 1.4
—
—
—
—
—
—
Other Operation (0.4 ) (0.1 ) (0.1 ) —
(0.1 ) —
—
Maintenance (0.5 ) (0.1 ) —
—
(0.1 ) —
(0.1 )
Regulatory Assets (a) (6.4 ) 0.6
(2.1 ) 0.3
(8.9 ) 0.5
(0.1 )
Regulatory Liabilities (a) (22.0 ) —
(31.7 ) 6.6
—
6.2
4.7
Total Gain (Loss) on Risk Management Contracts $ (24.9 ) $ 0.4
$ (34.0 ) $ 7.2
$ (9.1 ) $ 6.7
$ 4.6


	Three Months Ended March 31, 2020
Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	0.4	$	0	$	0	$	0	$	0	$	0	$	0

Generation & Marketing Revenues	(10.3)		0		0		0		0		0		0
Electric Generation, Transmission and Distribution Revenues	0		0		0.2		0.1		0		0		0


Purchased Electricity for Resale	0.1		0		0.1		0		0		0		0
Other Operation	(0.2)		(0.1)		0		0		(0.1)		0		0
Maintenance	(0.2)		(0.1)		(0.1)		0		0		0		0
Regulatory Assets (a)	(33.9)		(1.2)		(8.9)		(0.7)		(18.4)		(0.5)		(0.2)
Regulatory Liabilities (a)	11.2		0		(7.3)		3.2		3.5		8.1		3.3
Total Gain (Loss) on Risk Management Contracts	$	(32.9)	$	(1.4)	$	(16.0)	$	2.6	$	(15.0)	$	7.6	$	3.1


~~(a)~~	~~Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.~~

(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

157

Accounting for Fair Value Hedging Strategies (Applies to AEP)

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts net income during the period of change.

AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.

The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:


	Carrying Amount of the Hedged Liabilities				Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
	March 31, 2021		December 31, 2020		March 31, 2021		December 31, 2020
	(in millions)
Long-term Debt (a) (b)	$	(959.4)	$	(995.9)	$	(16.6)	$	(51.7)

Carrying Amount of the Hedged Liabilities Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
March 31, 2020 December 31, 2019 March 31, 2020 December 31, 2019
(in millions)
Long-term Debt (a) $ (553.4 ) $ (510.8 ) $ (57.0 ) $ (14.5 )

(a)Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.

(b)Amounts include $(51) million and $(53) million as of March 31, 2021 and December 31, 2020, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.


~~(a)~~	~~Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.~~

The pretax effects of fair value hedge accounting on income were as follows:


	Three Months Ended March 31,
	2021		2020
	(in millions)
Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a)	$	(33.2)	$	42.5
Fair Value Portion of Long-term Debt (a)	33.2		(42.5)

Three Months Ended March 31,
2020 2019
(in millions)
Gain (Loss) on Interest Rate Contracts:
Gain on Fair Value Hedging Instruments (a) $ 42.5
$ 11.1
Loss on Fair Value Portion of Long-term Debt (a) (42.5 ) (11.1 )

(a)Gain (Loss) is included in Interest Expense on the statements of income.


~~(a)~~	~~Gain (Loss) is included in Interest Expense on the statements of income.~~

In June 2020, AEP terminated a $500 million notional amount interest rate swap resulting in the discontinuance of the hedging relationship. A gain of $57 million on the fair value of the hedging instrument was settled in cash and recorded within operating activities on the statements of cash flows. Subsequent to the discontinuation of hedge accounting, the remaining adjustment to the carrying amount of the hedged item of $57 million will be amortized on a straight line basis through November 2027 in Interest Expense on the statements of income.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income.

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, AEP applied cash flow hedging to outstanding power derivatives. During the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives.

158

The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2021 and 2020, AEP and APCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. ~~During the three months ended March 31, 2019, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives.~~

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were:

Impact of Cash Flow Hedges on AEP’s Balance Sheets


	March 31, 2021				December 31, 2020
	Commodity		Interest Rate		Commodity		Interest Rate
	(in millions)
AOCI Loss Net of Tax	$	(18.5)	$	(33.3)	$	(60.6)	$	(47.5)
Portion Expected to be Reclassed to Net Income During the Next Twelve Months	(0.3)		(5.1)		(27.1)		(5.7)

March 31, 2020 December 31, 2019
Commodity Interest Rate Commodity Interest Rate
(in millions)
AOCI Gain (Loss) Net of Tax $ (128.5 ) $ (53.5 ) $ (103.5 ) $ (11.5 )
Portion Expected to be Reclassed to Net Income During the Next Twelve Months (73.2 ) (4.3 ) (51.7 ) (2.1 )

As of March 31, ~~2020~~2021 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is ~~132~~120 months and ~~129~~117 months for commodity and interest rate hedges, respectively.

Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets

March 31, 2020 December 31, 2019
Interest Rate
Expected to be Expected to be
Reclassified to Reclassified to
Net Income During Net Income During
AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next
Company Net of Tax Twelve Months Net of Tax Twelve Months
(in millions)
AEP Texas $ (3.1 ) $ (1.1 ) $ (3.4 ) $ (1.1 )
APCo (3.3 ) 1.1
0.9
0.9
I&M (9.5 ) (1.6 ) (9.9 ) (1.6 )
PSO 0.9
0.9
1.1
1.0
SWEPCo (1.4 ) (1.5 ) (1.8 ) (1.5 )

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.

Collateral Triggering Events

Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo)

A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. AEP had two derivative contracts with collateral triggering events in a net liability position as of March 31, 2021, however the exposure is immaterial. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of March 31, 2021. The Registrants had no derivative contracts with collateral triggering events in a net liability position as of ~~March 31, 2020 and~~ December 31, ~~2019, respectively.~~2020.

Cross-Default Triggers (Applies to AEP, APCo, I&M and SWEPCo)

In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements:

December 31, 2019
Liabilities for Additional
Contracts with Cross Settlement
Default Provisions Liability if Cross
Prior to Contractual Amount of Cash Default Provision
Company Netting Arrangements Collateral Posted is Triggered
(in millions)
AEP $ 267.3
$ 3.7
$ 246.7
APCo 2.3
—
0.4
I&M 1.3
—
0.2
SWEPCo 5.1
—
5.1

Warrants Held in Investee (Applies to AEP)

AEP holds an investment in ChargePoint, which completed an initial public offering (IPO) in February 2021 via a reverse merger with a public special purpose acquisition company. Before the IPO, AEP’s interests in ChargePoint consisted of a noncontrolling equity interest of preferred shares, which were accounted for at their historical cost of $8 million as of December 31, 2020, and common share warrants. After the IPO, AEP’s interests in ChargePoint consisted of a noncontrolling equity interest of common shares, which were accounted for at their fair value of $35 million as of March 31, 2021, and common share warrants. AEP recorded an unrealized gain of $27 million associated with the common shares for the three months ended March 31, 2021, presented in Other Income (Expense) on AEP’s statements of income.

Management has determined the common share warrants are derivative instruments based on the accounting guidance for “Derivatives and Hedging”. As of March 31, 2021 and December 31, 2020, the warrants were valued at $22 million and $32 million, respectively, and were recorded in Deferred Charges and Other Noncurrent Assets on AEP’s balance sheets. AEP recognized an unrealized loss of $10 million associated with the warrants for the three months ended March 31, 2021, presented in Other Income (Expense) on AEP’s statements of income.



Term		Meaning

AEGCo		AEP Generating Company, an AEP electric utility subsidiary.
AEP		American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit		AEP Credit, Inc., a consolidated VIE of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP System		American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Texas		AEP Texas Inc., an AEP electric utility subsidiary.
AEP Transmission Holdco		AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.

AEPEP		AEP ~~Wind Holdings LLC~~	~~Acquired~~Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in ~~April 2019 as Sempra Renewables LLC, develops, owns and operates, or holds interests in, wind generation facilities in the United States.~~deregulated markets.
AEPRO		AEP River Operations, LLC, a commercial barge operation sold in November 2015.
AEPSC		American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo		AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AEPTCo Parent		AEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation.
AFUDC		Allowance for Equity Funds Used During Construction.
AGR		AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
AMI		Advanced Metering Infrastructure.
AMR		Automated Meter Reading.
AOCI		Accumulated Other Comprehensive Income.
APCo		Appalachian Power Company, an AEP electric utility subsidiary.
Appalachian Consumer Rate Relief Funding		Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ~~ENEC~~Expanded Net Energy Cost deferral balance.
APSC		Arkansas Public Service Commission.
~~ARAM~~		~~Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for rate-making purposes.~~
ARO		Asset Retirement Obligations.

ASU		Accounting Standards Update.
CAA		Clean Air Act.
~~Cardinal Operating~~
CARES Act		Coronavirus Aid, Relief, and Economic Security Act signed into law in March 2020.
CCR		Coal Combustion Residual.
CLECO		Central Louisiana Electric Company,	~~A jointly-owned organization between AGR and~~ a ~~nonaffiliate. The nonaffiliate operates the three unit Cardinal Plant and wholly-owns Units 2 and 3.~~nonaffiliated utility company.
CO₂		Carbon dioxide and other greenhouse gases.
Conesville Plant		A retired, single unit coal-fired generation plant totaling 651 MW located in Conesville, Ohio. The plant was jointly-owned by AGR and a nonaffiliate.
Cook Plant		Donald C. Cook Nuclear Plant, a two-unit, 2,288 MW nuclear plant owned by I&M.
COVID-19		Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CSAPR		Cross-State Air Pollution Rule.
~~CWA~~	~~Clean Water Act.~~
CWIP		Construction Work in Progress.
DCC Fuel		DCC Fuel IX, DCC Fuel X, DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, DCC Fuel XIV and DCC Fuel ~~XIV,~~XV, consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.



~~Term~~	~~Meaning~~
	DHLC is a non-consolidated VIE of SWEPCo.
DIR			Distribution Investment Rider.
EIS			Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.
~~ENEC~~ELG			~~Expanded Net Energy Cost.~~Effluent Limitation Guidelines.

Energy Supply			AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
Equity Units			AEP’s Equity Units issued in August 2020 and March 2019.
ERCOT			Electric Reliability Council of Texas regional transmission organization.
ESP			Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT			Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADIT			Excess accumulated deferred income taxes.
FAC			Fuel Adjustment Clause
FASB			Financial Accounting Standards Board.
Federal EPA			United States Environmental Protection Agency.
FERC			Federal Energy Regulatory Commission.
FGD			Flue Gas Desulfurization or scrubbers.
FIP			Federal Implementation Plan.
FTR			Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP			Accounting Principles Generally Accepted in the United States of America.
~~Global Settlement~~		In February 2017, the PUCO approved a settlement agreement filed by OPCo in December 2016 which resolved all remaining open issues on remand from the Supreme Court of Ohio in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings. It also resolved all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
IRS			Internal Revenue Service.
IURC			Indiana Utility Regulatory Commission.
KGPCo			Kingsport Power Company, an AEP electric utility subsidiary.
KPCo			Kentucky Power Company, an AEP electric utility subsidiary.

KPSC			Kentucky Public Service Commission.
KWh			Kilowatt-hour.
LPSC			Louisiana Public Service Commission.
MATS			Mercury and Air Toxic Standards.
MISO			Midcontinent Independent System Operator.
MMBtu			Million British Thermal Units.
MPSC			Michigan Public Service Commission.
MTM			Mark-to-Market.
MW			Megawatt.
MWh			Megawatt-hour.
NAAQS			National Ambient Air Quality Standards.
Nonutility Money Pool			Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
North Central Wind Energy Facilities			A ~~proposed~~ joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,485 MWs of wind generation.
NO₂			~~Nitrogen dioxide.~~
NO_x			Nitrogen oxide.
~~NPDES~~			~~National Pollutant Discharge Elimination System.~~
NSR			New Source Review.
OCC			Corporation Commission of the State of Oklahoma.



~~Term~~	~~Meaning~~

~~Ohio Phase-in-Recovery Funding~~	~~Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.~~
Oklaunion Power Station		A retired, single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant iswas jointly-owned by AEP Texas, PSO and certain nonaffiliated entities.
OPCo		Ohio Power Company, an AEP electric utility subsidiary.



~~Term~~	~~Meaning~~

State Transcos		AEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP’s existing utility operating companies.
SWEPCo		Southwestern Electric Power Company, an AEP electric utility subsidiary.
Tax Reform		On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
~~TCC~~


~~(a)~~	~~Percentage change for the year ended December 31, 2019 as compared to the year ended December 31, 2018.~~


~~(b)~~	~~As presented in the 2019 AEP 10-K: Forecasted percentage change for the year ended December 31, 2020 compared to the year ended December 31, 2019.~~


~~(c)~~	~~Revised for the impact of COVID-19: Forecasted percentage change for the year ended December 31, 2020 compared to the year ended December 31, 2019.~~


~~(a)~~	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. 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.


~~(b)~~	In April 2020, the PUCT issued an order approving the stipulation and settlement agreement with a capital structure of 57.5% debt and 42.5% common equity effective with the first billing cycle in June 2020.



Owner	Plant Name	Units	State	Net Book Value as of March 31, 2020		Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
				(in millions)
AGR	Racine	2	OH	$	43.2	48	1982
APCo	London	3	WV	9.6		14	1935
APCo	Marmet	3	WV	11.0		14	1935
APCo	Winfield	3	WV	13.9		15	1938
I&M	Berrien Springs	12	MI	7.7		6	1908
I&M	Buchanan	10	MI	5.1		3	1919
I&M	Constantine	4	MI	2.6		1	1921
I&M	Elkhart	3	IN	5.5		3	1913
I&M	Mottville	4	MI	2.9		2	1923
I&M	Twin Branch Hydro	8	IN	7.1		5	1904
	Total			$	108.6	111



		Generating	Amounts Pending
Company	Plant Name and Unit	Capacity	Regulatory Approval
		(in MWs)	(in millions)
APCo (a)	Kanawha River Plant	400	$	14.0
APCo (b)	Clinch River Plant	705	25.3
APCo (a)	Sporn Plant, Units 1 and 3	300	2.0
APCo (a)	Glen Lyn Plant	335	3.4
SWEPCo (c)	Welsh Plant, Unit 2	528	35.5
Total		2,268	$	80.2



First Quarter of 2019	$	124.2

Changes in Transmission Revenues:
Transmission Revenues	53.8
Total Change in Transmission Revenues	53.8

Changes in Expenses and Other:
Other Operation and Maintenance	(7.6		)
Depreciation and Amortization	(16.3		)
Taxes Other Than Income Taxes	(9.3		)
Other Income	0.2
Allowance for Equity Funds Used During Construction	4.9
Non-Service Cost Components of Net Periodic Pension Cost	(0.1		)
Interest Expense	(7.8		)
Total Change in Expenses and Other	(36.0		)

Income Tax Expense	(6.5		)
Equity Earnings of Unconsolidated Subsidiary	5.1

First Quarter of 2020	$	140.6



	March 31, 2020				December 31, 2019
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	27,892.7	53.3	%	$	26,725.5	54.1	%
Short-term Debt	4,464.1		8.5		2,838.3		5.7
Total Debt	32,356.8		61.8		29,563.8		59.8
AEP Common Equity	19,728.4		37.7		19,632.2		39.6
Noncontrolling Interests	279.3		0.5		281.0		0.6
Total Debt and Equity Capitalization	$	52,364.5	100.0	%	$	49,477.0	100.0	%



	Cash Flow Hedges						Pension
Three Months Ended March 31, 2019	Commodity			Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2018	$	(23.0	)	$	(12.6	)	$	(84.8	)	$	(120.4	)
Change in Fair Value Recognized in AOCI	(38.8		)	—			—			(38.8		)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity for Resale (b)	12.3			—			—			12.3
Interest Expense (b)	—			0.2			—			0.2
Amortization of Prior Service Cost (Credit)	—			—			(4.8		)	(4.8		)
Amortization of Actuarial (Gains) Losses	—			—			3.0			3.0
Reclassifications from AOCI, before Income Tax (Expense) Benefit	12.3			0.2			(1.8		)	10.7
Income Tax (Expense) Benefit	2.6			—			(0.4		)	2.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	9.7			0.2			(1.4		)	8.5
Net Current Period Other Comprehensive Income (Loss)	(29.1		)	0.2			(1.4		)	(30.3		)
Balance in AOCI as of March 31, 2019	$	(52.1	)	$	(12.4	)	$	(86.2	)	$	(150.7	)


Plant	Net Investment		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	$	190.5	$	114.8	$	19.8	(b)	2026	(c)	$	14.9
Dolet Hills Power Station	51.3		92.6		1.1			2021	(d)	7.7
Pirkey Power Plant	178.3		30.8		18.4			2023	(e)	13.7
Welsh Plant, Units 1 and 3	528.8		14.2		11.4		(f)	2028	(g)	33.3



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


~~(a)~~	In October 2018, PSO changed depreciation rates to utilize the 2020 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously OCC-approved depreciation rates for Oklaunion Power Station.


~~(b)~~	In January 2020, SWEPCo changed depreciation rates to utilize the 2026 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously APSC-approved depreciation rates for Dolet Hills Power Station. In March 2020, SWEPCo changed depreciation rates again to utilize the accelerated 2021 end-of-life.


~~(a)~~	~~In April 2020, $26 million of deferred expenses were approved for recovery. See “2019 Texas Base Rate Case” section below for additional information.~~


~~(b)~~	~~Approved for recovery in the first quarter of 2020 in the Indiana Base Rate Case.~~


Company	Maximum Potential Loss
	(in millions)
AEP	$	48.6
AEP Texas	11.3
APCo	6.3
I&M	4.2
OPCo	7.7
PSO	4.7
SWEPCo	5.4


Future Minimum Lease Payments	AEP (a)		I&M
	(in millions)
2021	$	147.8	$	73.9
2022	147.6		73.8
Total Future Minimum Lease Payments	$	295.4	$	147.7


~~(a)~~	~~AEP’s future minimum lease payments include equal shares from AEGCo and I&M.~~


	March 31, 2021
	Risk Management Contracts		Hedging Contracts				Gross Amounts of Risk Management Assets/ Liabilities Recognized		Gross Amounts Offset in the Statement of Financial Position (b)		Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)		Commodity (a)		Interest Rate (a)
	(in millions)
Current Risk Management Assets	$	164.1	$	34.8	$	2.7	$	201.6	$	(129.5)	$	72.1
Long-term Risk Management Assets	266.9		18.8		0		285.7		(20.9)		264.8
Total Assets	431.0		53.6		2.7		487.3		(150.4)		336.9

Current Risk Management Liabilities	133.6		34.8		0		168.4		(129.3)		39.1
Long-term Risk Management Liabilities	219.8		41.6		37.4		298.8		(25.8)		273.0
Total Liabilities	353.4		76.4		37.4		467.2		(155.1)		312.1

Total MTM Derivative Contract Net Assets (Liabilities)	$	77.6	$	(22.8)	$	(34.7)	$	20.1	$	4.7	$	24.8


	March 31, 2021
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in millions)
AEP	$	156.8	$	0	$	127.7
APCo	0.6		0		0.1
I&M	0.4		0		0.1


SWEPCo	0.9		0		0.9


~~(a)~~	The fair value amount includes debt related to AEP’s Equity Units issued in March 2019 and has a fair value of $777 million and $871 million as of March 31, 2020 and December 31, 2019, respectively. See “Equity Units” section of Note 12 for additional information.


	March 31, 2021
			Gross		Gross
			Unrealized		Unrealized		Fair
Other Temporary Investments	Cost		Gains		Losses		Value
	(in millions)
Restricted Cash and Other Cash Deposits (a)	$	74.6	$	0	$	0	$	74.6
Fixed Income Securities – Mutual Funds (b)	116.7		2.0		0		118.7
Equity Securities – Mutual Funds	24.9		31.7		0		56.6
Total Other Temporary Investments	$	216.2	$	33.7	$	0	$	249.9


~~(a)~~	~~Primarily represents amounts held for the repayment of debt.~~


~~(b)~~	~~Primarily short and intermediate maturities which may be sold and do not contain maturity dates.~~


~~(a)~~	Amount reported as Gross Unrealized Gains includes unrealized gains of $801 million and $1.1 billion and unrealized losses of $23 million and $5 million as of March 31, 2020 and December 31, 2019, respectively.


	Fair Value of Fixed
	Income Securities
	(in millions)
Within 1 year	$	320.5
After 1 year through 5 years	334.7
After 5 years through 10 years	233.6
After 10 years	270.3
Total	$	1,159.1


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)



Other Temporary Investments
Restricted Cash and Other Cash Deposits (a)	$	62.9	$	0	$	0	$	11.7	$	74.6
Fixed Income Securities – Mutual Funds	118.7		0		0		0		118.7
Equity Securities – Mutual Funds (b)	56.6		0		0		0		56.6
Total Other Temporary Investments	238.2		0		0		11.7		249.9

Risk Management Assets
Risk Management Commodity Contracts (c) (d)	1.2		217.9		194.8		(94.8)		319.1
Cash Flow Hedges:
Commodity Hedges (c)	0		44.4		2.7		(32.0)		15.1

Fair Value Hedges	0		2.7		0		0		2.7
Total Risk Management Assets	1.2		265.0		197.5		(126.8)		336.9

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	39.5		0		0		8.2		47.7
Fixed Income Securities:
United States Government	0		998.9		0		0		998.9
Corporate Debt	0		76.4		0		0		76.4
State and Local Government	0		83.8		0		0		83.8
Subtotal Fixed Income Securities	0		1,159.1		0		0		1,159.1
Equity Securities – Domestic (b)	2,207.5		0		0		0		2,207.5
Total Spent Nuclear Fuel and Decommissioning Trusts	2,247.0		1,159.1		0		8.2		3,414.3

Other Investments (h)	0		56.7		0		0		56.7

Total Assets	$	2,486.4	$	1,480.8	$	197.5	$	(106.9)	$	4,057.8

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)	$	0.8	$	182.7	$	152.8	$	(99.5)	$	236.8
Cash Flow Hedges:
Commodity Hedges (c)	0		67.0		2.9		(32.0)		37.9

Fair Value Hedges	0		37.4		0		0		37.4
Total Risk Management Liabilities	$	0.8	$	287.1	$	155.7	$	(131.5)	$	312.1


~~(a)~~	Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.


~~(b)~~	~~Amounts represent publicly traded equity securities and equity-based mutual funds.~~