UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
 
FORM 10-K
 
(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
or
☐ 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		The NASDAQ Stock Market LLC	
American Electric Power Company Inc.		6.125% Corporate Units		AEPPL		The NASDAQ Stock Market LLC	
American Electric Power Company Inc.		6.125% Corporate Units		AEPPZ		The NASDAQ Stock Market LLC	

Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark if the registrant American Electric Power Company, Inc., AEP Texas Inc., AEP Transmission Company, LLC, Ohio Power Company and Southwestern Electric Power Company, are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.	Yes	x	No	¨	
					
Indicate by check mark if the registrants Appalachian Power Company, Indiana Michigan Power Company and Public Service Company of Oklahoma, are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.	Yes	¨	No	x	
					
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.	Yes	¨	No	x	
					
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	x	No	¨	
					
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 registrant was required to submit such files).	Yes	x	No	¨	

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	x	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	x			
 	 	 	 	 	 			
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 registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.	
		☒				

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).		Yes	☐		No	x	

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 I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.

															
 		Aggregate Market Value of Voting and Non-Voting Common Equity Held by Nonaffiliates of the Registrants as of June 30, 2020 the Last Trading Date of the Registrants' Most Recently Completed Second Fiscal Quarter		Number of Shares of Common Stock Outstanding of the Registrants as of December 31, 2020	
American Electric Power Company, Inc.		$39,549,558,010		496,604,194 		
 		 		($6.50 par value)	
AEP Texas Inc.		None		100 		
				($0.01 par value)	
AEP Transmission Company, LLC (a)		None		NA	
					
Appalachian Power Company		None		13,499,500 		
 		 		(no par value)	
Indiana Michigan Power Company		None		1,400,000 		
 		 		(no par value)	
Ohio Power Company		None		27,952,473 		
 		 		(no par value)	
Public Service Company of Oklahoma		None		9,013,000 		
 		 		($15 par value)	
Southwestern Electric Power Company		None		3,680 		
 		 		($18 par value)	
(a)100% interest is held by AEP Transmission Holdco.
NA    Not applicable.

Note on Market Value of Common Equity Held by Nonaffiliates

American Electric Power Company, Inc. owns all of the common stock of AEP Texas Inc., Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company and, indirectly, all of the LLC membership interest in AEP Transmission Company, LLC (see Item 12 herein).

Documents Incorporated By Reference

Description	 	Part of Form 10-K into which Document is Incorporated	
 	 	 	
Portions of Annual Reports of the following companies for the fiscal year ended December 31, 2020:	 	Part II	
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	 	 	
Southwestern Electric Power Company	 	 	
 	 	 	
Portions of Proxy Statement of American Electric Power Company, Inc. for 2021 Annual Meeting of Shareholders.	 	Part III	

This combined Form 10-K 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.  Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants.

You can access financial and other information at AEP’s website, including AEP’s Principles of Business Conduct, certain committee charters and Principles of Corporate Governance.  The address is www.AEP.com.  Investors can obtain copies of our SEC filings from this site free of charge, as well as from the SEC website at www.sec.gov.

TABLE OF CONTENTS

Item
Number	 	Page
Number	
 	Glossary of Terms	i	
 	Forward-Looking Information	vi	
			
PART I	
1	Business	 	
 	General	1	
 	Business Segments	17	
 	Vertically Integrated Utilities	17	
 	Transmission and Distribution Utilities	24	
 	AEP Transmission Holdco	26	
 	Generation & Marketing	29	
 	Executive Officers of AEP	32	
1A	Risk Factors	34	
1B	Unresolved Staff Comments	46	
2	Properties	46	
 	Generation Facilities	46	
 	Transmission and Distribution Facilities	50	
 	Title to Property	51	
 	System Transmission Lines and Facility Siting	51	
 	Construction Program	51	
 	Potential Uninsured Losses	52	
3	Legal Proceedings	52	
4	Mine Safety Disclosure	52	
			
PART II	
5	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	53	
6	Reserved	54	
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	54	
7A	Quantitative and Qualitative Disclosures about Market Risk	54	
8	Financial Statements and Supplementary Data	54	
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	420	
9A	Controls and Procedures	420	
9B	Other Information	420	
			
	PART III		
10	Directors, Executive Officers and Corporate Governance	421	
11	Executive Compensation	421	
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	422	
13	Certain Relationships and Related Transactions and Director Independence	422	
14	Principal Accounting Fees and Services	423	
			
PART IV	
15	Exhibits and Financial Statement Schedules		
 	Financial Statements	424	
	Form 10-K Summary	425	
 	Signatures	426	
 	Index of Financial Statement Schedules	S-1	
 	Report of Independent Registered Public Accounting Firm	S-2	
 	Exhibit Index	E-1	

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
									
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 East Companies		APCo, I&M, KGPCo, KPCo, OPCo and WPCo.	
AEP Energy		AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.	
AEP Energy Supply, LLC		A nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.	
AEP OnSite Partners		A division of AEP Energy Supply, LLC that builds, owns, operates and maintains customer solutions utilizing existing and emerging distributed technologies.	
AEP Renewables		A division of AEP Energy Supply, LLC that develops and/or acquires large scale renewable projects that are backed with long-term contracts with creditworthy counter parties.	
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.	
AEP Utilities		AEP Utilities, Inc., a former subsidiary of AEP and holding company for TCC, TNC and CSW Energy, Inc.  Effective December 31, 2016, TCC and TNC were merged into AEP Utilities, Inc.  Subsequently following this merger, the assets and liabilities of CSW Energy, Inc. were transferred to a competitive affiliate company and AEP Utilities, Inc. was renamed AEP Texas Inc.	
AEP Wind Holdings LLC		Acquired in April 2019 as Sempra Renewables LLC, develops, owns and operates, or holds interests in, wind generation facilities in the United States.	
AEPEP		AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in 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.	
AEPTHCo	 	AEP Transmission Holding Company, LLC, a subsidiary of AEP, an intermediate holding company that owns transmission operations joint ventures and AEPTCo.	
AFUDC	 	Allowance for Equity Funds Used During Construction.	
AGR	 	AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.	
ALJ		Administrative Law Judge.	
AMI		Advanced Metering Infrastructure.	
AMT		Alternative Minimum Tax.	
AOCI		Accumulated Other Comprehensive Income.	
APCo	 	Appalachian Power Company, an AEP electric utility subsidiary.	
i

									
Term	 	Meaning	
 	 	 	
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 deferral balance.	
APTCo		AEP Appalachian Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.	
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.	
CAA of 2021		Consolidated Appropriations Act of 2021 signed into law in December 2020.	
Cardinal Operating 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.	
CARES Act		Coronavirus Aid, Relief, and Economic Security Act signed into law in March 2020.	
CLECO		Central Louisiana Electric Company, a 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.	
CRES provider		Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service.	
CSAPR		Cross-State Air Pollution Rule.	
CSPCo	 	Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.	
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 XV, consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.	
Desert Sky		Desert Sky Wind Farm LLC, a 170 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas in which AEP owns a 100% interest.	
DHLC		Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.	
DIR		Distribution Investment Rider.	
DOE		U. S. Department of Energy.	
EIS		Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.	
ENEC		Expanded Net Energy Cost.	
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.	
ii

									
Term	 	Meaning	
 	 	 	
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 FAC Audits.	
I&M	 	Indiana Michigan Power Company, an AEP electric utility subsidiary.	
IMTCo		AEP Indiana Michigan Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.	
IRS		Internal Revenue Service.	
ITC		Investment Tax Credit.	
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.	
KTCo		AEP Kentucky Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.	
kV		Kilovolt.	
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.	
NERC		North American Electric Reliability Corporation.	
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 joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,485 MWs of wind generation.	
NO2		Nitrogen dioxide.	
NOL		Net operating losses.	
NOx	 	Nitrogen oxide.	
NPDES		National Pollutant Discharge Elimination System.	
NRC	 	Nuclear Regulatory Commission.	
NSR		New Source Review.	
OATT	 	Open Access Transmission Tariff.	
OCC	 	Corporation Commission of the State of Oklahoma.	
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. In July 2019, the Ohio Phase-in Recovery funding securitization bonds matured.	
iii

									
Term	 	Meaning	
 	 	 	
OHTCo		AEP Ohio Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.	
Oklaunion Power Station		A retired, single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant was jointly-owned by AEP Texas, PSO and certain nonaffiliated entities.	
OKTCo		AEP Oklahoma Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.	
OPCo	 	Ohio Power Company, an AEP electric utility subsidiary.	
OPEB		Other Postretirement Benefits.	
Operating Agreement		Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third-party sales.  AEPSC acts as the agent.	
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.	
PCA		Power Coordination Agreement among APCo, I&M, KPCo and WPCo.	
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.	
REP	 	Texas Retail Electric Provider.	
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 and operate a 302 MW wind generation facility in west Texas in which AEP owns an 85% interest.	
iv

									
Term	 	Meaning	
 	 	 	
SEC	 	U.S. Securities and Exchange Commission.	
SEET		Significantly Excessive Earnings Test.	
Sempra Renewables LLC		Sempra Renewables LLC, acquired in April 2019, consists of 724 MWs of wind generation and battery assets in the United States.	
SIA		System Integration Agreement, effective June 15, 2000, as amended, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.	
SIP		State Implementation Plan.	
SNF		Spent Nuclear Fuel.	
SO2	 	Sulfur dioxide.	
SPP	 	Southwest Power Pool regional transmission organization.	
SSO		Standard service offer.	
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.	
SWTCo		AEP Southwestern Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.	
TA	 	Transmission Agreement, effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.	
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.	
TCA	 	Transmission Coordination Agreement dated January 1, 1997, by and among, PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two public utility subsidiaries.	
TCC		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.	
TNC	 	Formerly AEP Texas North Company; now a division of AEP 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 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 LLC 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.	
Trent		Trent Wind Farm LLC, a 156 MW wind electricity generation facility located between Abilene and Sweetwater in west Texas in which AEP owns a 100% interest.	
Turk Plant		John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.	
UMWA		United Mine Workers of America.	
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.	
WPCo	 	Wheeling Power Company, an AEP electric utility subsidiary.	
WVPSC	 	Public Service Commission of West Virginia.	
WVTCo		AEP West Virginia Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.	
v

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 – Management’s Discussion and Analysis of Financial Condition and Results of Operations,” 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.	
vi

						
•	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 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, except as required by law.  For a more detailed discussion of these factors, see “Risk Factors” in Part I 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.
vii

PART I

ITEM 1.   BUSINESS

GENERAL

Overview and Description of Major Subsidiaries

AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries.

The service areas of AEP’s public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring laws in Michigan, Ohio and the ERCOT area of Texas have caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers.

The member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.

As of December 31, 2020, the subsidiaries of AEP had a total of 16,787 employees. Because it is a holding company rather than an operating company, AEP has no employees. The material subsidiaries of AEP are as follows:

AEP Texas

Organized in Delaware in 1925, AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,068,000 retail customers through REPs in west, central and southern Texas.  As of December 31, 2020, AEP Texas had 1,570 employees.  Among the principal industries served by AEP Texas are petroleum and coal products manufacturing, chemical manufacturing, oil and gas extraction, pipeline transportation and primary metal manufacturing.  The territory served by AEP Texas also includes several military installations and correctional facilities.  AEP Texas is a member of ERCOT.  AEP Texas is part of AEP’s Transmission and Distribution Utilities segment.

AEPTCo

Organized in Delaware in 2006, AEPTCo is a holding company for the State Transcos. The State Transcos develop and own new transmission assets that are physically connected to the AEP System.  Individual State Transcos (a) have obtained the approvals necessary to operate in Indiana, Kentucky, Michigan, Ohio, Oklahoma and West Virginia, subject to any applicable siting requirements, (b) are authorized to submit projects for commission approval in Virginia and (c) have been granted consent to enter into a joint license agreement that will support investment in Tennessee. Neither AEPTCo nor its subsidiaries have any employees. Instead, AEPSC and certain AEP utility subsidiaries provide services to these entities. AEPTCo is part of the AEP Transmission Holdco segment.

1

APCo

Organized in Virginia in 1926, APCo is engaged in the generation, transmission and distribution of electric power to approximately 964,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. APCo owns 6,629 MWs of generating capacity.  APCo uses its generation to serve its retail and other customers.  As of December 31, 2020, APCo had 1,652 employees. Among the principal industries served by APCo are coal-mining, primary metals, pipeline transportation, chemical manufacturing and paper manufacturing. APCo is a member of PJM.  APCo is part of AEP’s Vertically Integrated Utilities segment.

I&M

Organized in Indiana in 1907, I&M is engaged in the generation, transmission and distribution of electric power to approximately 602,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants.  I&M owns or leases 3,634 MWs of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2020, I&M had 2,217 employees. Among the principal industries served are primary metals, transportation equipment, chemical manufacturing, plastics and rubber products and fabricated metal product manufacturing.  I&M is a member of PJM.  I&M is part of AEP’s Vertically Integrated Utilities segment.

KPCo

Organized in Kentucky in 1919, KPCo is engaged in the generation, transmission and distribution of electric power to approximately 166,000 retail customers in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants.  KPCo owns 1,060 MWs of generating capacity.  KPCo uses its generation to serve its retail and other customers.  As of December 31, 2020, KPCo had 475 employees. Among the principal industries served are petroleum and coal products manufacturing, chemical manufacturing, coal-mining, oil and gas extraction and primary metals.  KPCo is a member of PJM.  KPCo is part of AEP’s Vertically Integrated Utilities segment.

KGPCo

Organized in Virginia in 1917, KGPCo provides electric service to approximately 49,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. KGPCo does not own any generating facilities and is a member of PJM. It purchases electric power from APCo for distribution to its customers. As of December 31, 2020, KGPCo had 52 employees. KGPCo is part of AEP’s Vertically Integrated Utilities segment.

OPCo

Organized in Ohio in 1907 and re-incorporated in 1924, OPCo is engaged in the transmission and distribution of electric power to approximately 1,507,000 retail customers in Ohio.  OPCo purchases energy and capacity at auction to serve generation service customers who have not switched to a competitive generation supplier.  As of December 31, 2020, OPCo had 1,646 employees.  Among the principal industries served by OPCo are primary metals, petroleum and coal products manufacturing, plastics and rubber products, chemical manufacturing, fabricated metal product manufacturing and data centers. OPCo is a member of PJM.  OPCo is part of AEP’s Transmission and Distribution Utilities segment.

2

PSO

Organized in Oklahoma in 1913, PSO is engaged in the generation, transmission and distribution of electric power to approximately 565,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants.  PSO owns 3,728 MWs of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2020, PSO had 1,023 employees. Among the principal industries served by PSO are paper manufacturing, oil and gas extraction, petroleum and coal products manufacturing, transportation equipment and pipeline transportation. PSO is a member of SPP.  PSO is part of AEP’s Vertically Integrated Utilities segment.

SWEPCo

Organized in Delaware in 1912, SWEPCo is engaged in the generation, transmission and distribution of electric power to approximately 545,000 retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. SWEPCo owns 5,034 MWs of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2020, SWEPCo had 1,440 employees. Among the principal industries served by SWEPCo are petroleum and coal products manufacturing, food manufacturing, paper manufacturing, oil and gas extraction and chemical manufacturing. The territory served by SWEPCo includes several military installations, colleges and universities. SWEPCo also owns and operates a lignite coal-mining operation. SWEPCo is a member of SPP.  SWEPCo is part of AEP’s Vertically Integrated Utilities segment.

WPCo

Organized in West Virginia in 1883 and re-incorporated in 1911, WPCo provides electric service to approximately 42,000 retail customers in northern West Virginia and in supplying and marketing electric power at wholesale to other market participants. WPCo owns 780 MWs of generating capacity which it uses to serve its retail and other customers. Among the principal industries served by WPCo are coal-mining, primary metals, pipeline transportation, chemical manufacturing and paper manufacturing. WPCo is a member of PJM. As of December 31, 2020, WPCo had 45 employees.  WPCo is part of AEP’s Vertically Integrated Utilities segment.

Service Company Subsidiary

AEPSC is a service company subsidiary that provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to AEP subsidiaries. The executive officers of AEP and certain of the executive officers of its public utility subsidiaries are employees of AEPSC. As of December 31, 2020, AEPSC had 6,295 employees.

Company Website and Availability of SEC Filings

Our principal corporate website address is www.aep.com. Information on our website is not incorporated by reference herein and is not part of this Form 10-K. We make available free of charge through our website our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such documents are electronically filed with, or furnished to, the SEC. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding AEP.

3

Public Utility Subsidiaries by Jurisdiction

The following table illustrates certain regulatory information with respect to the jurisdictions in which the public utility subsidiaries of AEP operate:

Principal Jurisdiction		AEP Utility Subsidiaries Operating in that Jurisdiction		Authorized Return on Equity (a)		
FERC		AEPTCo - PJM		10.35%		
		AEPTCo - SPP		10.50%		
						
Ohio		OPCo		10.20%	(b)	
						
West Virginia		APCo		9.75%		
 		WPCo		9.75%		
						
Virginia		APCo		9.20%		
						
Indiana		I&M		9.70%		
						
Michigan		I&M		9.86%		
						
Texas		AEP Texas		9.40%		
 		SWEPCo		9.60%		
						
Tennessee		KGPCo		9.85%		
						
Kentucky		KPCo		9.30%	(c)	
						
Louisiana		SWEPCo		9.80%		
						
Arkansas		SWEPCo		9.45%		
						
Oklahoma		PSO		9.40%		

(a)Identifies the predominant current authorized ROE, and may not include other, less significant, permitted recovery.  Actual ROE varies from authorized ROE.
(b)Authorized ROE was approved in OPCo’s last distribution base case. The authorized ROE for riders with an approved equity return (e.g. Distribution Investment Rider) is 10.00%.
(c)Final order received and made effective in January 2021 that approved an authorized ROE of 9.30%. The authorized ROE for riders with an approved equity return (Decommissioning Rider and the Environmental Surcharge) is 9.10%.

(a)Pretax income does not include intercompany eliminations.

4

CLASSES OF SERVICE

The principal classes of service from which AEP’s subsidiaries derive revenues and the amount of such revenues during the years ended December 31, 2020, 2019 and 2018 are as follows:

 		Years Ended December 31,	
Description		2020		2019		2018	
 		(in millions)	
Vertically Integrated Utilities Segment		 		 		 	
Retail Revenues		 		 		 	
Residential Sales		$	3,614.8 			$	3,641.2 			$	3,818.6 		
Commercial Sales		2,021.0 			2,151.1 			2,223.7 		
Industrial Sales		2,023.5 			2,178.3 			2,261.3 		
PJM Net Charges		(0.1)			(0.2)			0.4 		
	
Other Retail Sales		155.9 			179.4 			186.8 		
Total Retail Revenues		7,815.1 			8,149.8 			8,490.8 		
Wholesale Revenues		 		 		 	
Off-system Sales		589.3 			814.5 			888.0 		
Transmission		249.5 			200.7 			263.7 		
Total Wholesale Revenues		838.8 			1,015.2 			1,151.7 		
Other Electric Revenues		85.8 			93.8 			93.7 		
Provision for Rate Refund		(21.7)			(44.7)			(210.1)		
Other Operating Revenues		35.2 			31.6 			30.6 		
Sales to Affiliates		126.2 			121.4 			88.8 		
Total Revenues Vertically Integrated Utilities Segment		$	8,879.4 			$	9,367.1 			$	9,645.5 		
							
Transmission and Distribution Utilities Segment		 		 		 	
Retail Revenues		 		 		 	
Residential Sales		$	2,114.9 			$	2,084.5 			$	2,213.6 		
Commercial Sales		1,049.5 			1,148.8 			1,266.7 		
Industrial Sales		390.0 			426.5 			517.2 		

Other Retail Sales		42.5 			43.7 			43.1 		
Total Retail Revenues		3,596.9 			3,703.5 			4,040.6 		
Wholesale Revenues		 		 		 	
Off-system Sales		60.6 			93.0 			119.3 		
Transmission		471.8 			437.7 			394.7 		
Total Wholesale Revenues		532.4 			530.7 			514.0 		
Other Electric Revenues		95.0 			58.6 			54.5 		
Provision for Rate Refund		2.3 			12.5 			(69.2)		
Other Operating Revenues		12.1 			13.7 			12.4 		
Sales to Affiliates		107.2 			163.5 			100.8 		
Total Revenues Transmission and Distribution Utilities Segment		$	4,345.9 			$	4,482.5 			$	4,653.1 		
							
AEP Transmission Holdco Segment							
Transmission Revenues		$	315.1 			$	265.1 			$	291.3 		
Other Electric Revenues		0.4 			0.3 			0.3 		
Other Operating Revenues		0.6 			0.1 			0.3 		
Sales to Affiliates		901.4 			812.9 			555.5 		
Provision for Rate Refund		(18.7)			(5.2)			(43.3)		
Total Revenues AEP Transmission Holdco Segment		$	1,198.8 			$	1,073.2 			$	804.1 		
							
Generation & Marketing Segment		 		 		 	
Generation Revenues - Nonaffiliated		$	136.4 			$	264.4 			$	431.5 		

Renewable Generation - Nonaffiliated		85.7 			77.7 			44.5 		

Retail, Trading and Marketing				 			
Affiliated		104.6 			135.7 			122.2 		
Nonaffiliated		1,398.9 			1,379.8 			1,342.1 		
Total Revenues Generation & Marketing Segment		$	1,725.6 			$	1,857.6 			$	1,940.3 		

5

AEP Texas

 		Years Ended December 31,	
Description		2020		2019		2018	
 		(in millions)	
Retail Revenues		 		 		 	
Residential Sales		$	562.3 			$	588.9 			$	594.6 		
Commercial Sales		365.9 			424.0 			426.6 		
Industrial Sales		119.9 			133.3 			131.0 		

Other Retail Sales		29.4 			30.8 			30.1 		
Total Retail Revenues		1,077.5 			1,177.0 			1,182.3 		
Wholesale Revenues		 		 		 	
	
Transmission		399.9 			379.2 			313.4 		
	
Other Electric Revenues		45.2 			24.4 			21.9 		
Provision for Rate Refund		2.3 			(34.7)			(31.3)		
Total Electric Transmission and Distribution Revenues		1,524.9 			1,545.9 			1,486.3 		
Sales to Affiliates		90.8 			160.5 			105.2 		
Other Revenues		3.2 			2.9 			3.8 		
Total Revenues		$	1,618.9 			$	1,709.3 			$	1,595.3 		

AEPTCo

 		Years Ended December 31,	
Description		2020		2019		2018	
 		(in millions)	
Transmission Revenues		$	264.4 			$	217.2 			$	212.8 		
Other Electric Revenues		0.4 			0.3 			0.3 		
Other Operating Revenues		0.6 			0.1 			0.2 		
Sales to Affiliates		896.3 			806.7 			598.9 		
Provision for Rate Refund		(16.0)			(2.9)			(36.1)		
Total Revenues		$	1,145.7 			$	1,021.4 			$	776.1 		

APCo

 		Years Ended December 31,	
Description		2020		2019		2018	
 		(in millions)	
Retail Revenues		 		 		 	
Residential Sales		$	1,250.4 			$	1,272.3 			$	1,372.1 		
Commercial Sales		517.0 			562.2 			596.3 		
Industrial Sales		553.3 			594.5 			620.7 		
PJM Net Charges		(0.3)			(0.2)			(0.2)		
	
Other Retail Sales		67.6 			75.6 			79.5 		
Total Retail Revenues		2,388.0 			2,504.4 			2,668.4 		
Wholesale Revenues		 		 		 	
Off-system Sales		118.1 			124.9 			116.4 		
Transmission		71.0 			57.0 			56.3 		
Total Wholesale Revenues		189.1 			181.9 			172.7 		
Other Electric Revenues		34.0 			32.3 			31.1 		
Provision for Rate Refund		(0.2)			(10.4)			(95.1)		
Total Electric Generation, Transmission and Distribution Revenues		2,610.9 			2,708.2 			2,777.1 		
Sales to Affiliates		174.7 			205.3 			181.4 		
Other Revenues		10.6 			11.2 			9.0 		
Total Revenues		$	2,796.2 			$	2,924.7 			$	2,967.5 		
6

I&M

 		Years Ended December 31,	
Description		2020		2019		2018	
 		(in millions)	
Retail Revenues		 		 		 	
Residential Sales		$	794.1 			$	730.9 			$	736.5 		
Commercial Sales		499.4 			494.9 			489.3 		
Industrial Sales		547.5 			551.4 			570.6 		
PJM Net Charges		0.2 			0.1 			0.2 		
	
Other Retail Sales		6.6 			7.3 			7.2 		
Total Retail Revenues		1,847.8 			1,784.6 			1,803.8 		
Wholesale Revenues		 		 		 	
Off-system Sales		275.4 			406.4 			459.3 		
Transmission		31.0 			19.3 			18.4 		
Total Wholesale Revenues		306.4 			425.7 			477.7 		
Other Electric Revenues		11.3 			14.4 			15.7 		
Provision for Rate Refund		(0.2)			(2.6)			(24.6)		
Total Electric Generation, Transmission and Distribution Revenues		2,165.3 			2,222.1 			2,272.6 		
Sales to Affiliates		71.3 			73.9 			85.5 		
Other Revenues		5.2 			10.7 			12.6 		
Total Revenues		$	2,241.8 			$	2,306.7 			$	2,370.7 		

OPCo

 		Years Ended December 31,	
Description		2020		2019		2018	
 		(in millions)	
Retail Revenues		 		 		 	
Residential Sales		$	1,552.6 			$	1,495.6 			$	1,619.0 		
Commercial Sales		683.5 			724.9 			840.1 		
Industrial Sales		270.1 			293.2 			386.2 		

Other Retail Sales		13.1 			12.9 			13.0 		
Total Retail Revenues		2,519.3 			2,526.6 			2,858.3 		
Wholesale Revenues		 		 		 	
Off-system Sales		60.6 			93.0 			119.3 		
Transmission		68.8 			58.5 			61.4 		
Total Wholesale Revenues		129.4 			151.5 			180.7 		
Other Electric Revenues		49.9 			34.2 			32.7 		
Provision for Rate Refund		— 			47.2 			(37.9)		
Total Electricity, Transmission and Distribution Revenues		2,698.6 			2,759.5 			3,033.8 		
Sales to Affiliates		41.5 			27.3 			21.0 		
Other Revenues		9.0 			10.8 			8.6 		
Total Revenues		$	2,749.1 			$	2,797.6 			$	3,063.4 		

PSO

 		Years Ended December 31,	
Description		2020		2019		2018	
 		(in millions)	
Retail Revenues		 		 		 	
Residential Sales		$	579.8 			$	636.1 			$	668.5 		
Commercial Sales		320.4 			377.3 			401.1 		
Industrial Sales		221.2 			296.5 			308.5 		
	
Other Retail Sales		66.0 			80.7 			84.5 		
Total Retail Revenues		1,187.4 			1,390.6 			1,462.6 		
Wholesale Revenues		 		 		 	
Off-system Sales		15.1 			39.5 			36.3 		
Transmission		35.3 			31.9 			47.4 		
Total Wholesale Revenues		50.4 			71.4 			83.7 		
Other Electric Revenues		10.4 			9.6 			10.3 		
Provision for Rate Refund		(2.1)			(2.0)			(19.0)		
Total Electric Generation, Transmission and Distribution Revenues		1,246.1 			1,469.6 			1,537.6 		
Sales to Affiliates		5.2 			6.1 			5.4 		
Other Revenues		14.8 			6.1 			4.3 		
Total Revenues		$	1,266.1 			$	1,481.8 			$	1,547.3 		
7

SWEPCo

 		Years Ended December 31,	
Description		2020		2019		2018	
 		(in millions)	
Retail Revenues		 		 		 	
Residential Sales		$	637.4 			$	645.3 			$	666.0 		
Commercial Sales		471.5 			490.6 			502.6 		
Industrial Sales		332.1 			342.3 			346.2 		
	
Other Retail Sales		9.1 			9.1 			8.9 		
Total Retail Revenues		1,450.1 			1,487.3 			1,523.7 		
Wholesale Revenues		 		 		 	
Off-system Sales		162.0 			194.7 			216.8 		
Transmission		87.0 			72.6 			94.2 		
Total Wholesale Revenues		249.0 			267.3 			311.0 		
Other Electric Revenues		16.5 			20.6 			20.9 		
Provision for Rate Refund		(19.0)			(30.6)			(63.7)		
Total Electric Generation, Transmission and Distribution Revenues		1,696.6 			1,744.6 			1,791.9 		
Sales to Affiliates		39.0 			4.9 			28.4 		
Other Revenues		2.9 			1.4 			1.6 		
Total Revenues		$	1,738.5 			$	1,750.9 			$	1,821.9 		

FINANCING

General

Companies within the AEP System generally use short-term debt to finance working capital needs.  Short-term debt may also be used to finance acquisitions, construction and redemption or repurchase of outstanding securities until such needs can be financed with long-term debt.  In recent history, short-term funding needs have been provided for by cash on hand and AEP’s commercial paper program.  Funds are made available to subsidiaries under the AEP corporate borrowing program.  Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity.  See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

AEP’s revolving credit agreement (which backstops the commercial paper program) includes covenants and events of default typical for this type of facility, including a maximum debt/capital test.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of its 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 the credit agreement. As of December 31, 2020, AEP was in compliance with its debt covenants.  With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the agreement.  A voluntary bankruptcy or insolvency of AEP or one of its significant subsidiaries would be considered an immediate termination event.  See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

AEP’s subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as securitization financings and leasing arrangements, including the leasing of coal transportation equipment and facilities.

ENVIRONMENTAL AND OTHER MATTERS

General

AEP subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities.  The environmental issues that management believes are potentially material to the AEP System are outlined below.

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Clean Water Act Requirements

Operations for AEP subsidiaries are subject to the CWA, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits and regulates systems that withdraw surface water for use in power plants.  In 2014, the Federal EPA issued a final rule setting forth standards for water withdrawals at existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  The standards affect all plants withdrawing more than two million gallons of cooling water per day.  A schedule for compliance with the standard is established by the permit agency and incorporated in NPDES permits.

In November 2015, the Federal EPA issued a final rule revising effluent limitation guidelines for electricity generating facilities. The rule established limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater to be imposed in NPDES permits as soon as possible after November 2018 and no later than December 2023.  The Federal EPA further revised the rule in August 2020 for FGD wastewater and bottom ash transport water extending the compliance date to December 2025 and establishing additional options. In January 2020, the Federal EPA issued a final rule revising the scope of the “waters of the United States” subject to CWA regulation. See “Environmental Issues - Clean Water Act Regulations” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Coal Ash Regulation

AEP’s operations produce a number of different coal combustion by-products, including fly ash, bottom ash, gypsum and other materials.  A rule by the Federal EPA regulates the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units.  The rule requires certain standards for location, groundwater monitoring and dam stability to be met at landfills and certain surface impoundments at operating facilities. If existing disposal facilities cannot meet these standards, they will be required to close. See “Environmental Issues - Coal Combustion Residual Rule” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control mobile and stationary sources of air emissions.  The major CAA programs affecting AEP’s power plants are described below.  The states implement and administer many of these programs and could impose additional or more stringent requirements.

The Acid Rain Program

The CAA includes a cap-and-trade emission reduction program for SO2 emissions from power plants and requirements for power plants to reduce NOx emissions through the use of available combustion controls, collectively called the Acid Rain Program. AEP continues to meet its obligations under the Acid Rain Program through the installation of controls, use of alternate fuels and participation in the emissions allowance markets. 

National Ambient Air Quality Standards

The CAA requires the Federal EPA to review the available scientific data for criteria pollutants periodically and establish a concentration level in the ambient air for those substances that is adequate to protect the public health and welfare with an extra safety margin.  The Federal EPA also can list additional pollutants and develop concentration levels for them.  These concentration levels are known as NAAQS.

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Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (non-attainment areas).  Each state must develop a SIP to bring non-attainment areas into compliance with the NAAQS and maintain good air quality in attainment areas.  All SIPs are submitted to the Federal EPA for approval.  If a state fails to develop adequate plans, the Federal EPA develops and implements a plan.  As the Federal EPA reviews the NAAQS and establishes new concentration levels, the attainment status of areas can change and states may be required to develop new SIPs.  See “Environmental Issues - Clean Air Act Requirements” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Hazardous Air Pollutants (HAP)

The CAA also requires the Federal EPA to investigate HAP emissions from the electric utility sector and submit a report to Congress to determine whether those emissions should be regulated. In 2011, the Federal EPA issued a rule setting Maximum Achievable Control Technology standards for new and existing coal and oil-fired utility units and New Source Performance Standards for emissions from new and modified power plants.  In 2014, the U.S. Supreme Court determined that the Federal EPA acted unreasonably in refusing to consider costs in determining if it was appropriate and necessary to regulate HAP emissions from electric generating units. The Federal EPA has engaged in additional rulemaking activity but the 2011 rule remains in effect. See “Environmental Issues - Mercury and Other Hazardous Air Pollutants Regulation” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Regional Haze

The CAA establishes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing impairment of visibility in these protected areas.  In 2005, the Federal EPA issued its Clean Air Visibility Rule, detailing how the CAA’s best available retrofit technology requirements will be applied to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.

PSO executed a settlement with the Federal EPA and the State of Oklahoma to comply with Regional Haze program requirements in Oklahoma, and the settlement is now codified in the Oklahoma SIP and approved by the Federal EPA. The Federal EPA disapproved portions of the Arkansas and Texas SIPs, and finalized FIPs for both states.  Arkansas submitted and received approval of a revised SIP, and the Federal EPA developed a revised FIP for Texas. See “Environmental Issues - Clean Air Act Requirements” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Climate Change

AEP has taken action to reduce and offset CO2 emissions from its generating fleet and expects CO2 emissions from its operations to continue to decline due to the retirement of coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. In 2021, AEP announced revised 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, regulations, grid reliability and resiliency, and reflect the company’s current business strategy. The intermediate goal is an 80% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is net-zero CO2 emissions from AEP generating facilities by 2050. AEP’s total estimated CO2 emissions in 2020 were approximately 44 million metric tons, a 73% reduction from AEP’s 2000 CO2 emissions. AEP will publish a new report in 2021 on the results of a climate change scenario analysis.

To date, the Federal EPA has twice taken action to regulate CO2 emissions from new and existing fossil fueled electric generating units under the existing provisions of the CAA.  The Clean Power Plan was adopted in October 2015 but the U.S. Supreme Court issued a stay of its implementation, including all of the deadlines for submission
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of initial or final state plans. The Clean Power Plan was repealed by the Federal EPA in 2019 and replaced by the Affordable Clean Energy (ACE) Rule, which changed the Federal EPA’s approach to regulating CO2 emissions from existing coal-fired generating units. In January 2021, the ACE Rule was vacated by the U.S. Court of Appeals for the District of Columbia Circuit and remanded to the Federal EPA for further proceedings. It is too soon to predict how the Federal EPA will respond to the court’s remand. Management expects emissions to continue to decline over time as AEP diversifies generating sources and operates fewer coal units.  The projected decline in coal-fired generation is due to a number of factors, including the ongoing cost of operating older units, the relative cost of coal and natural gas as fuel sources, increasing environmental regulations requiring significant capital investments and changing commodity market fundamentals.

Transforming AEP’s Generation Fleet

The electric utility industry is in the midst of an historic transformation, driven by changing customer needs, policy demands, demographics, competitive offerings, technologies and commodity prices. AEP is also transforming to be more agile and customer-focused as a valued provider of energy solutions.  AEP’s long-term commitment to reduce CO2 emissions reflects the current direction of the company’s resource plans to meet those needs as well a new climate change scenario analysis to be published in 2021.  AEP’s exposure to carbon regulation has been greatly reduced over the last several years.  From 2000 to 2020, AEP’s CO2 emissions declined 73%.  In 2020, coal represented 44% of AEP’s generating capacity compared with 70% in 2005. Management expects the percentage of AEP’s generating resources fueled by coal will continue to decline and to represent only 24% of generating capacity by 2030. The long-term goal is net-zero CO2 emissions from AEP generating facilities by 2050.  Transforming AEP’s generation portfolio to include, where there is regulatory support, more renewable energy and focusing on the efficient use of energy, demand response, distributed resources and technology solutions to more efficiently manage the grid over time is part of this strategy.

The graph below summarizes AEP’s generation capacity by resource type for the years 1999, 2005 and 2020:

(a)    Energy Efficiency/Demand Response represents avoided capacity rather than physical assets.

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Renewable Sources of Energy

The states AEP serves, other than Kentucky, West Virginia and Tennessee, have established mandatory or voluntary programs to increase the use of energy efficiency, alternative energy or renewable energy sources.

As of December 31, 2020, AEP’s regulated utilities had long-term contracts for 2,750 MWs of wind, 80 MWs of hydro, and 10 MWs of solar power delivering renewable energy to the companies’ customers. In addition, I&M owns four solar projects that make up I&M’s 16 MW Clean Energy Solar Pilot Project. Management actively manages AEP’s compliance position and is on pace to meet the relevant requirements or benchmarks in each applicable jurisdiction.

In 2020, PSO received approval from the OCC and SWEPCo received approval from the 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. Both the APSC and LPSC approved the flex-up option, agreeing to 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.

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, will qualify for 80% of the federal PTC.

Having regulatory approval, and the expectation that all three wind facilities will be eligible for the IRS extension of the “Continuity Safe Harbor,” PSO and SWEPCo are proceeding with the full 1,485 MW development of these three projects. The 199 MW wind facility is targeted to be acquired and placed in-service in March 2021. The 287 MW wind facility is targeted to be acquired and placed in-service in December 2021 and the 999 MW wind facility is targeted to be acquired and placed in-service between December 2021 and April 2022.

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.  In addition to gradually reducing AEP’s reliance on coal-fueled generating units, the growth of renewables and natural gas helps AEP to maintain a diversity of generation resources.

The integrated resource plans filed with state regulatory commissions by AEP’s regulated utility subsidiaries reflect AEP’s renewable strategy to balance reliability and cost with customers’ desire for clean energy in a carbon-constrained world.  AEP has committed significant capital investments to modernize the electric grid and integrate these new resources.  Transmission assets of the AEP System interconnect approximately 16,300 MWs of renewable energy resources.  AEP’s transmission development initiatives are designed to facilitate the interconnection of additional renewable energy resources.

AEP Energy Supply, LLC is a holding company with several divisions, including AEP Renewables and AEP OnSite Partners.

AEP Renewables develops, owns and operates utility scale renewable projects backed with long-term contracts with creditworthy counterparties throughout the United States.  AEP Renewables works directly with stakeholders to ensure that customers have clean, sustainable renewable energy to meet their environmental goals.  As of December 31, 2020, AEP Renewables owned projects operating in 11 states, including approximately 1,307 MWs of installed wind capacity and 90 MWs of installed solar capacity.  These figures include the 2020 acquisition of an additional 10% interest, or approximately 30 MWs, of Santa Rita East wind generation located in west Texas. In October 2019, AEP Renewables entered into an agreement to construct Flat Ridge 3, a wind farm in Kansas.  The 128 MW facility is expected to reach commercial operation by May 2021.

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AEP OnSite Partners works directly with wholesale and large retail customers to provide tailored solutions to reduce their energy costs based upon market knowledge, innovative applications of technology and deal structuring capabilities.  AEP OnSite Partners targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions that create value for customers.  AEP OnSite Partners pursues and develops behind the meter projects with creditworthy customers.  As of December 31, 2020, AEP OnSite Partners owned projects located in 21 states, including approximately 152 MWs of installed solar capacity, and approximately 9 MWs of solar projects under construction.

Competitive Renewable Generation Facilities

Size of
Energy Resource		AEP Energy Supply, LLC Division		Renewable
Energy Resource		Location		In-Service or
Under Construction	
1,307 MW		AEP Renewables		Wind		Eight states (a)		In-service	
128 MW		AEP Renewables		Wind		Kansas		Under Construction	
20 MW		AEP Renewables		Solar		California		In-service	
20 MW		AEP Renewables		Solar		Utah		In-service	
50 MW		AEP Renewables		Solar		Nevada		In-service	
152 MW		AEP OnSite Partners		Solar		Sixteen states (b)		In-service	
9 MW		AEP OnSite Partners		Solar		Two states (c)		Under Construction	

(a)    Colorado, Hawaii, Indiana, Kansas, Michigan, Minnesota, Pennsylvania, and Texas.
(b)    California, Colorado, Florida, Hawaii, Illinois, Iowa, Minnesota, Nebraska, New Hampshire, New Jersey, New Mexico, New York, Ohio, Rhode Island, Texas and Vermont.
(c)    Ohio and Wisconsin.

End Use Energy Efficiency

AEP has reduced energy consumption and peak demand through the introduction of additional energy efficiency and demand response programs.  These programs, commonly referred to as demand-side management, were implemented in jurisdictions where appropriate cost recovery was available.  AEP’s operating companies’ programs have reduced annual consumption by over 9 million MWhs and peak demand by approximately 2,900 MWs since 2008.  AEP estimates that its operating companies spent approximately $1.5 billion during that period to achieve these levels.

Energy efficiency and demand reduction programs have received regulatory support in most of the states AEP serves. Appropriate cost recovery will be essential for AEP operating companies to continue and expand these consumer offerings. Appropriate recovery of program costs, lost revenues and an opportunity to earn a reasonable return ensures that energy efficiency programs are considered equally with supply side investments.  As AEP continues to transition to a cleaner, more efficient energy future, energy efficiency and demand response programs will continue to play an important role in how the company serves its customers. AEP believes its experience providing robust energy efficiency programs in several states positions the company to be a cost-effective provider of these programs as states develop their implementation plans.

Corporate Governance

In response to environmental issues and in connection with its assessment of AEP’s strategic plan, the Board of Directors continually reviews the risks posed by new environmental rules and requirements that could accelerate the retirement of coal-fired generation assets. The Board of Directors is informed of any new environmental regulations and proposed regulation or legislation that would significantly affect AEP.  The Board’s Committee on Directors and Corporate Governance oversees AEP’s annual Corporate Accountability Report, which includes information about AEP’s environmental, social, governance and financial performance. AEP set CO2 emission reduction goals in 2018 after considering input from corporate governance outreach effort with shareholders.

In 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 an 80%
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reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is net-zero CO2 emissions from AEP generating facilities by 2050. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. Technological advances, including advanced energy storage, modular nuclear, and green hydrogen, and public policies are among the factors that will determine how quickly AEP can achieve net-zero emissions while continuing to provide reliable, affordable power for customers. AEP will publish a new report in 2021 on the results of a climate change scenario analysis.

Other Environmental Issues and Matters

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 imposes costs for environmental remediation upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites.  See “The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation” section of Note 6 included in the 2020 Annual Report for additional information.

Environmental Investments

Investments related to improving AEP System plants’ environmental performance and compliance with air and water quality standards during 2018, 2019 and 2020 and the current estimate for 2021 are shown below. These investments include both environmental as well as other related spending. Estimated construction 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 and the ability to access capital.  In addition to the amounts set forth below, AEP expects to make substantial investments in future years in connection with the modification and addition at generation plants’ facilities for environmental quality controls.  Such future investments are needed in order to comply with air and water quality standards that have been adopted and have deadlines for compliance after 2020 or have been proposed and may be adopted.  Future investments could be significantly greater if emissions reduction requirements are accelerated or otherwise become more stringent. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System. AEP typically recovers costs of complying with environmental standards from customers through rates in regulated jurisdictions.  Failure to recover these costs could reduce future net income and cash flows and possibly harm AEP’s financial condition.  See “Environmental Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 6 - Commitments, Guarantees and Contingencies included in the 2020 Annual Report for additional information.

Historical and Projected Environmental Investments	
									
 		2018		2019		2020		2021	
 		Actual		Actual		Actual		Estimate (b)	
 		(in millions)	
AEP (a)		$	115.6 			$	167.1 			$	102.2 			$	133.8 		
AEP Texas		— 			(0.2)			— 			— 		
APCo		20.4 			23.8 			21.3 			60.6 		
I&M		31.1 			56.4 			31.8 			16.8 		
	
SWEPCo		14.1 			10.5 			(3.6)			8.8 		

(a)Includes expenditures of the subsidiaries shown and other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies.
(b)Estimated amounts are exclusive of debt AFUDC.

Management continues to refine the cost estimates of complying with air and water quality standards and other impacts of the environmental proposals. The following cost estimates for the years 2021 through 2027 will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  These cost estimates will also change based on: (a) potential state rules that impose more stringent standards,
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(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. Management’s current ranges of estimates of new major environmental investments beginning in 2021, exclusive of debt AFUDC, are set forth below:

Projected (2021 - 2027)
Environmental Investment	
Company		Low		High	
		(in millions)	
AEP		$	350 			$	700 		
APCo		175 			290 		
I&M		25 			45 		
PSO		5 			10 		
SWEPCo		45 			90 		

HUMAN CAPITAL MANAGEMENT

Attracting, developing and retaining employees with the skills and experience needed to provide service to our customers efficiently and effectively is crucial to our long-term success and is central to our long-term strategy. AEP invests in employees and continues to build a high performance and inclusive culture that inspires leadership, encourages innovative thinking and welcomes everyone.

The following table shows AEP’s number of employees by subsidiary as of December 31, 2020:

Subsidiary		Number of Employees	
AEPSC		6,295 		
AEP Texas		1,570 		
APCo		1,652 		
I&M		2,217 		
OPCo		1,646 		
PSO		1,023 		
SWEPCo		1,440 		
Other		944 		
Total AEP		16,787 		

Of AEP’s 16,787 employees, less than 1% are Traditionalists (born before 1946), approximately 27% are Baby Boomers (born 1946-1964), approximately 37% are Generation X (born 1965-1980), approximately 34% are Millennials (born 1981-1996) and approximately 1% are Generation Z (born after 1996).

Safety

Achieving Zero Harm means every employee returns home at the end of their shift in the same or better condition than when they came to work. Zero Harm is what we value most and commit to wholeheartedly. It is hard work, as it requires full focus every moment of every day. We hold ourselves accountable and we are always striving to be better. For AEP, Zero Harm is not an option; it is a mandate we live by. AEP has put tools, training and processes in place to strengthen our safety-first culture and mindset. AEP’s focus is on learning from events and developing leading indicators to be even more proactive in preventing harm. One common industry safety metric utilized by AEP to track incidents is the Days Away/Restricted or Transferred (DART) rate. A DART event is an event that results in one or more lost days, one or more restricted days or results in an employee transferring to a different job within the company. The DART rate is a mathematical calculation (number of DART events multiplied by 200,000 work hours and divided by total YTD hours worked) that describes the number of recordable injuries per 100 full-time employees. In 2020, AEP recognized its best safety performance in the past five years with an employee DART Rate of 0.310.
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Diversity and Inclusion

AEP is committed to cultivating a diverse and inclusive environment that supports the development and advancement of all. We foster an inclusive workplace that encourages diversity of thought, culture and background, and actively work to eliminate unconscious biases. We believe our workforce should reﬂect the diversity of our customers and the communities we serve so that we may better understand how to tailor our services to meet their demands and expectations. As of December 31, 2020, females comprised approximately 20% of AEP’s workforce while approximately 19% was represented by minorities.

AEP has taken actions to denounce all forms of racism in the wake of the racial and social unrest across the country. AEP Chief Executive Officer (CEO) Nicholas Akins joined more than 1,400 other CEOs as a signatory to the CEO Action for Diversity and Inclusion pledge, the largest CEO-driven business commitment to advancing diversity and inclusion within the workplace. To accelerate our diversity and inclusion strategy, AEP has initiated a “Seize the Moment: Let’s Keep the Momentum Going” action plan that included candid conversations about race, Town Hall webcasts and “Let’s Talk” discussions with the top 20 African American leaders at AEP.

Culture

AEP believes in doing the right thing every time for our customers, each other and our future. AEP leaders at all levels are responsible for fostering an environment that supports a positive culture and for acting in a manner that positively models it. Employees are given an opportunity to share their perspectives by participating in the Employee Culture Survey, administered by Gallup, Inc., that measures the progress we are making in improving our culture. In addition to engagement, the survey measures well-being and inclusiveness. In 2020, 93% of our organization participated in the survey and we improved our grand mean score to the top decile compared to Gallup’s overall company database. Company executives also have candid meetings with employees to discuss our challenges, opportunities, what is going well and what can be even better.

Employee Resource Groups

One of the best ways for AEP to demonstrate our commitment to a trusting and inclusive work environment is to empower employees to form and participate in Employee Resource Groups (ERG). The ERGs at AEP include Abled and Disabled Allies Partnering Together, the African-American ERG, the Asian-American ERG, the Hispanic Origin Latin American ERG, the Military Veteran ERG, the Native American ERG and the Pride Partnership. Our ERGs reflect the diverse makeup of our workforce and enable us to gain valuable insight into the diverse communities we serve. They also help increase engagement across AEP by providing employees with a safe space to discuss work-related issues and to develop innovative solutions. ERGs also play an active role in AEP’s diversity and inclusion efforts, including recruitment of new employees. In addition to the ERG’s, AEP also sponsors the AEP Women’s Leadership Council. The mission of this council is to educate, inspire and encourage women to build confidence and reflect on their goals as they strive for career and personal growth.

Training and Professional Development

At AEP, we are preparing our workforce for the future by providing opportunities to learn new skills and engaging higher education institutions to better prepare the next generation with the skills that we will need. AEP has training alliances with several community colleges, universities and vocational and technical schools across our service territory. We work with these institutions to develop academic programs that will prepare employees for upward mobility opportunities and to attract external job seekers interested in careers in our industry. AEP also provides a broad range of training and assistance that supports lifelong learning and transition development. This is especially important as we move closer toward a digital future that requires a more flexible, innovative and diverse workforce. AEP has robust processes to achieve this, including ongoing performance coaching, operational skills training, resources to support our commitment to environment, safety and health, job progression training, tuition assistance, and other forms of training that help employees improve their skills and become better leaders.
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Compensation and Benefits

AEP recognizes the importance of our employees to our success and we offer physical, financial and other health, wellness and assistance programs to our associates and their families to help them thrive at home and work. We ensure the pay we offer is competitive in the marketplace by using an overall market pricing process. In addition to competitive wages, nearly all AEP employees participate in an annual incentive program that rewards outstanding performance and achievement of business goals. Our incentive compensation provides financial rewards to those who contribute to business results and meet or exceed their personal performance goals, which fosters a high performance culture. AEP also offers employees physical and mental health programs, including medical, dental and life insurance, along with a health and well-being program to help employees and their families stay healthy and feeling their best. Additionally, AEP’s retirement programs position our associates for financial stability in retirement.

Labor Relations

Nearly one fourth of AEP’s workforce is represented by labor unions. We value the relationships we have with our unionized employees and believe in a trusting, collaborative and respectful partnership. We are working with our labor partners to strengthen these relationships to ensure we have a culture that attracts and supports employees who can adapt to the rapid changes occurring in our company and industry. Our partnership with labor unions is critical to meeting the growing expectations of our customers and adapting to the challenges of rapidly changing technologies.

BUSINESS SEGMENTS

AEP’s Reportable 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 are as follows:

•Vertically Integrated Utilities
•Transmission and Distribution Utilities
•AEP Transmission Holdco
•Generation & Marketing

The remainder of AEP’s activities is presented as Corporate and Other, which is not considered a reportable segment. See Note 9 - Business Segments included in the 2020 Annual Report for additional information on AEP’s segments.

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VERTICALLY INTEGRATED UTILITIES

GENERAL

AEP’s vertically integrated utility operations are engaged in the 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.  AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities on behalf of each of these subsidiaries.

ELECTRIC GENERATION

Facilities

As of December 31, 2020, AEP’s vertically integrated public utility subsidiaries owned or leased approximately 22,000 MWs of domestic generation.  See Item 2 – Properties for more information regarding the generation capacity of vertically integrated public utility subsidiaries.

Fuel Supply

The following table shows the owned and leased generation sources by type (including wind purchase agreements), on an actual net generation (MWhs) basis, used by the Vertically Integrated Utilities:

 	2020		2019		2018	
Coal and Lignite	45%		54%		58%	
Nuclear	24%		19%		18%	
Natural Gas	18%		16%		14%	
Renewables	13%		11%		10%	

A price increase/decrease in one or more fuel sources relative to other fuels, as well as the addition of renewable resources or retirement of traditional fossil fuel units, may result in the decreased/increased use of other fuels.  AEP’s overall 2020 fossil fuel costs for the Vertically Integrated Utilities decreased 3% on a dollar per MMBtu basis from 2019.

Coal and Lignite

AEP’s Vertically Integrated Utilities procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers, marketers and coal trading firms.  Coal consumption in 2020 decreased approximately 27% from 2019 mainly due to lower dispatching of coal generation from weaker power market prices.

Management believes that the Vertically Integrated Utilities will be able to secure and transport coal and lignite of adequate quality and quantities to operate their coal and lignite-fired units. Through subsidiaries, AEP owns, leases or controls 3,016 railcars, 411 barges, 6 towboats and a coal handling terminal with approximately 18 million tons of annual capacity to move and store coal for use in AEP generating facilities.

Spot market prices for coal weakened during the first half of 2020 before stabilizing or slightly rebounding in the second half of 2020. The decreased spot coal prices reflect lower demand for domestic and export coal. AEP’s strategy for purchasing coal includes layering in supplies over time. The price impact of this process is reflected in subsequent periods and can occasionally cause current spot market prices to be trending opposite to the price of coal delivered. The price paid for coal delivered in 2020 increased approximately 18% from 2019 mainly due to lignite mine related activities and closure costs.

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The following table shows the amount of coal and lignite delivered to the Vertically Integrated Utilities’ plants during the past three years and the average delivered price of coal and lignite purchased by the Vertically Integrated Utilities:

 	2020		2019		2018	
Total coal and lignite delivered to the plants (in millions of tons)	19.4		30.4		29.0 		
Average cost per ton of coal and lignite delivered	$	53.95 			$	45.85 			$	43.21 		

The coal supplies at the Vertically Integrated Utilities plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. As of December 31, 2020, the Vertically Integrated Utilities’ coal inventory was approximately 64 days of full load burn. While inventory targets vary by plant and are changed as necessary, the current coal inventory target for the Vertically Integrated Utilities is approximately 30 days of full load burn.

Natural Gas

The Vertically Integrated Utilities consumed approximately 113 billion cubic feet of natural gas during 2020 for generating power. This represents a decrease of 3.33% from 2019. Several of AEP’s natural gas-fired power plants are connected to at least two pipelines which allow greater access to competitive supplies and improve delivery reliability. A portfolio of term, monthly and daily supply and transportation agreements provide natural gas requirements for each plant, as appropriate. AEP’s natural gas supply transactions are entered into on a competitive basis and based on market prices.

The following table shows the amount of natural gas delivered to the Vertically Integrated Utilities’ plants during the past three years and the average delivered price of natural gas purchased by the Vertically Integrated Utilities.

 	2020		2019		2018	
Total natural gas delivered to the plants (in billions cubic feet)	113.1 			117.0 			111.6 		
Average delivered price per MMBtu of purchased natural gas	$	2.14 			$	2.64 			$	3.26 		

Nuclear

I&M has made commitments to meet the current nuclear fuel requirements of the Cook Plant.  I&M has made and will make purchases of uranium in various forms in the spot, short-term and mid-term markets.  I&M also continues to finance its nuclear fuel through leasing.

For purposes of the storage of high-level radioactive waste in the form of SNF, I&M completed modifications to its SNF storage pool in the early 1990’s.  I&M entered into an agreement to provide for onsite dry cask storage of SNF to permit normal operations to continue.  I&M is scheduled to conduct further dry cask loading and storage projects on an ongoing periodic basis.  The year of expiration of each NRC Operating License is 2034 for Unit 1 and 2037 for Unit 2.

Nuclear Waste and Decommissioning

As the owner of the Cook Plant, I&M has a significant future financial commitment to dispose of SNF and decommission and decontaminate the plant safely.  The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program.  The most recent decommissioning cost study was completed in 2018.  The estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant was $2 billion in 2018 non-discounted dollars, with additional ongoing estimated costs of $6 million per year for post decommissioning storage of SNF and an eventual estimated cost of $37 million for the subsequent decommissioning of the spent fuel storage facility, also in 2018 non-discounted dollars. As of December 31, 2020 and 2019, the total decommissioning trust fund balance for the Cook Plant was approximately $3 billion and $2.7
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billion, respectively. The balance of funds available to eventually decommission Cook Plant will differ based on contributions and investment returns.  The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:

•Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy).
•Further development of regulatory requirements governing decommissioning.
•Technology available at the time of decommissioning differing significantly from that assumed in studies.
•Availability of nuclear waste disposal facilities.
•Availability of a United States Department of Energy facility for permanent storage of SNF.

Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections.  AEP will seek recovery from customers through regulated rates if actual decommissioning costs exceed projections.  See the “Nuclear Contingencies” section of Note 6 - Commitments, Guarantees and Contingencies included in the 2020 Annual Report for additional information with respect to nuclear waste and decommissioning.

Low-Level Radioactive Waste

The Low-Level Waste Policy Act of 1980 mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states.  Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials.  Michigan does not currently have a disposal site for such waste available.  I&M cannot predict when such a site may be available. However, the states of Utah and Texas have licensed low-level radioactive waste disposal sites which currently accept low-level radioactive waste from Michigan waste generators.  There is currently no set date limiting I&M’s access to either of these facilities.  The Cook Plant has a facility onsite designed specifically for the storage of low-level radioactive waste.  In the event that low-level radioactive waste disposal facility access becomes unavailable, it can be stored onsite at this facility.

Counterparty Risk Management

The Vertically Integrated Utilities segment also sells power and enters into related energy transactions with wholesale customers and other market participants. As a result, counterparties and exchanges may require cash or cash related instruments to be deposited on transactions as margin against open positions.  As of December 31, 2020, counterparties posted approximately $13 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries posted approximately $19 million with counterparties and exchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily.  See the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Certain Power Agreements

I&M

The UPA between AEGCo and I&M, dated March 31, 1982 (the I&M Power Agreement), provides for the sale by AEGCo to I&M of all the capacity (and the energy associated therewith) available to AEGCo at the Rockport Plant.  Whether or not power is available from AEGCo, I&M is obligated to pay a demand charge for the right to receive such power (and an energy charge for any associated energy taken by I&M).  The I&M Power Agreement will continue in effect until the debt obligations of AEGCo secured by the Rockport Plant have been satisfied and discharged (currently expected to be December 2028).

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Pursuant to an assignment between I&M and KPCo, and a UPA between AEGCo and KPCo, AEGCo sells KPCo 30% of the capacity (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant.  KPCo has agreed to pay to AEGCo the amounts that I&M would have paid AEGCo under the terms of the UPA between AEGCo and I&M for such entitlement.  The KPCo UPA expires in December 2022.

OVEC

AEP and several nonaffiliated utility companies jointly own OVEC.  The aggregate equity participation of AEP in OVEC is 43.47%.  Parent owns 39.17% and OPCo owns 4.3%.  Under the Inter-Company Power Agreement (ICPA), which defines the rights of the owners and sets the power participation ratio of each, the sponsoring companies are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios.  The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%.  The ICPA terminates in June 2040.  The proceeds from charges by OVEC to sponsoring companies under the ICPA based on their power participation ratios are designed to be sufficient for OVEC to meet its operating expenses and fixed costs.  OVEC’s Board of Directors, as elected by AEP and nonaffiliated owners, has authorized environmental investments related to their ownership interests, with resulting expenses (including for related debt and interest thereon) included in charges under the ICPA. OVEC financed capital expenditures totaling $1.3 billion in connection with flue gas desulfurization projects and the associated scrubber waste disposal landfills at its two generation plants through debt issuances, including tax-advantaged debt issuances.  Both OVEC generation plants are operating with the new environmental controls in-service.  See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.

ELECTRIC DELIVERY

General

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power.  See Item 2 – Properties for more information regarding the transmission and distribution lines.  Most of the transmission and distribution services are sold to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories.  These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC.  See Item 1. Business – Vertically Integrated Utilities – Regulation – Rates.  The FERC regulates and approves the rates for both wholesale transmission transactions and wholesale generation contracts.  The use and the recovery of costs associated with the transmission assets of the AEP vertically integrated public utility subsidiaries are subject to the rules, principles, protocols and agreements in place with PJM and SPP, and as approved by the FERC. See Item 1. Business – Vertically Integrated Utilities – Regulation – FERC.  As discussed below, some transmission services also are separately sold to nonaffiliated companies.

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas.  In some cases, these franchises provide the utility with the exclusive right to provide electric service within a specific territory.  These franchises have varying provisions and expiration dates.  In general, the operating companies consider their franchises to be adequate for the conduct of their business.  For a discussion of competition in the sale of power, see Item 1. Business – Vertically Integrated Utilities – Competition.

Transmission Agreement

APCo, I&M, KGPCo, KPCo and WPCo own and operate transmission facilities that are used to provide transmission service under the PJM OATT and are parties to the TA.  OPCo, which is a subsidiary in AEP’s Transmission and Distribution Utilities segment that provides transmission service under the PJM OATT, is also a party to the TA.  The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM.  The TA has been approved by the FERC.
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Transmission Coordination Agreement and Open Access Transmission Tariff

PSO, SWEPCo and AEPSC are parties to the TCA.  Under the TCA, a coordinating committee is charged with the responsibility of: (a) overseeing the coordinated planning of the transmission facilities of the parties to the agreement, including the performance of transmission planning studies, (b) the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and (c) compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff.  Pursuant to the TCA, AEPSC has responsibility for monitoring the reliability of their transmission systems and administering the OATT on behalf of the other parties to the agreement.  The TCA also provides for the allocation among the parties of revenues collected for transmission and ancillary services provided under the OATT.  These allocations have been determined by the FERC-approved OATT for the SPP.

Regional Transmission Organizations

AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM, and PSO and SWEPCo are members of SPP (both FERC-approved RTOs).  RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.

REGULATION

General

AEP’s vertically integrated public utility subsidiaries’ retail rates and certain other matters are subject to traditional cost-based regulation by the state utility commissions.  AEP’s vertically integrated public utility subsidiaries are also subject to regulation by the FERC under the Federal Power Act with respect to wholesale power and transmission service transactions.  I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant.  AEP and its vertically integrated public utility subsidiaries are also subject to the regulatory provisions of, much of the Energy Policy Act of 2005, which is administered by the FERC.

Rates

Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service.  A utility’s cost-of-service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes.  State utility commissions periodically adjust rates pursuant to a review of: (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.  Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time, a state utility commission can review and change rates on its own initiative.  Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers.  Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.

Public utilities have traditionally financed capital investments until the new asset is placed in-service.  Provided the asset was found to be a prudent investment, it was then added to rate base and entitled to a return through rate recovery.  Given long lead times in construction, the high costs of plant and equipment and volatile capital markets, management actively pursues strategies to accelerate rate recognition of investments and cash flow.  AEP representatives continue to engage state commissioners and legislators on alternative rate-making options to reduce regulatory lag and enhance certainty in the process.  These options include pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates.

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The rates of AEP’s vertically integrated public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service).  Historically, the state regulatory frameworks in the service area of the AEP vertically integrated public utility subsidiaries reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates and tariffs.  Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes.

The following state-by-state analysis summarizes the regulatory environment of certain major jurisdictions in which AEP’s vertically integrated public utility subsidiaries operate.  Several public utility subsidiaries operate in more than one jurisdiction.  See Note 4 - Rate Matters included in the 2020 Annual Report for more information regarding pending rate matters.

Indiana

I&M provides retail electric service in Indiana at bundled rates approved by the IURC, with rates set on a cost-of-service basis.  Indiana provides for timely fuel and purchased power cost recovery through a fuel cost recovery mechanism.

Oklahoma

PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC.  PSO’s rates are set on a cost-of-service basis.  Fuel and purchased energy costs are recovered or refunded by applying fuel adjustment and other factors to retail kilowatt-hour sales.

Virginia

APCo currently provides retail electric service in Virginia at unbundled generation and distribution rates approved by the Virginia SCC.  Virginia generally allows for timely recovery of fuel costs through a FAC.  In addition to base rates and fuel cost recovery, APCo is permitted to recover a variety of costs through rate adjustment clauses including transmission services provided at OATT rates based on rates established by the FERC.

West Virginia

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis.  West Virginia generally allows for timely recovery of fuel costs through the ENEC which trues-up to actual expenses.

FERC

The FERC regulates rates for interstate power sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects.  The FERC regulations require AEP’s vertically integrated public utility subsidiaries to provide open access transmission service at FERC-approved rates, and AEP has approved cost-based formula transmission rates on file at the FERC.  The FERC also regulates unbundled transmission service to retail customers.  In addition, the FERC regulates the sale of power for resale in interstate commerce by: (a) approving contracts for wholesale sales to municipal and cooperative utilities and (b) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices.  AEP’s vertically integrated public utility subsidiaries have market-based rate authority from the FERC, under which much of their wholesale marketing activity takes place.  The FERC requires each public utility that owns or controls interstate transmission facilities, directly or through an RTO, to file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system.  The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. Additionally, the vertically integrated public utility subsidiaries are subject to reliability standards promulgated by the NERC, with the approval of the FERC.
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The FERC oversees RTOs, entities created to operate, plan and control utility transmission assets.  AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM.  PSO and SWEPCo are members of SPP.

The FERC has jurisdiction over the issuances of securities of most of AEP’s public utility subsidiaries, the acquisition of securities of utilities, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company.  In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.

COMPETITION

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries generate, transmit and distribute electricity to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories.  These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC, and are not subject to competition from other vertically integrated public utilities.  Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights that effectively grant the exclusive ability to provide electric service in various municipalities and regions in their service areas.  

AEP’s vertically integrated public utility subsidiaries compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas.  The primary factors in such competition are price, reliability of service and the capability of customers to utilize alternative sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they currently maintain a competitive position. 

Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production.  The costs of photovoltaic solar cells in particular have continued to become increasingly competitive. The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AEP’s competitiveness.

SEASONALITY

The consumption of electric power is generally seasonal.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In other areas, power demand peaks during the winter.  The pattern of this fluctuation may change due to the nature and location of AEP’s facilities and the terms of power sale contracts into which AEP enters.  In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP’s results of operations. Conversely, unusually extreme weather conditions could increase AEP’s results of operations.

TRANSMISSION AND DISTRIBUTION UTILITIES

GENERAL

This segment consists of the transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo. OPCo is engaged in the transmission and distribution of electric power to approximately 1,507,000 retail customers in Ohio.  OPCo purchases energy and capacity to serve standard service offer customers and provides transmission and distribution services for all connected load. AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,068,000 retail customers through REPs in west, central and southern Texas.

AEP’s transmission and distribution utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power.  See Item 2 – Properties, for more information regarding the transmission
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and distribution lines.  Transmission and distribution services are sold to retail customers of AEP’s transmission and distribution utility subsidiaries in their service territories.  These sales are made at rates approved by the PUCT for AEP Texas and by the PUCO and the FERC for OPCo.  The FERC regulates and approves the rates for wholesale transmission transactions.  As discussed below, some transmission services also are separately sold to nonaffiliated companies.

AEP’s transmission and distribution utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas.  In some cases, these franchises provide the utility with the exclusive right to provide electric service.  These franchises have varying provisions and expiration dates.  In general, the operating companies consider their franchises to be adequate for the conduct of their business.

The use and the recovery of costs associated with the transmission assets of the AEP transmission and distribution utility subsidiaries are subject to the rules, protocols and agreements in place with PJM and ERCOT, and as approved by the FERC.  In addition to providing transmission services in connection with power sales in their service areas, AEP’s transmission and distribution utility subsidiaries also provide transmission services for nonaffiliated companies through RTOs.

Transmission Agreement

OPCo owns and operates transmission facilities that are used to provide transmission service under the PJM OATT; OPCo is a party to the TA with other utility subsidiary affiliates. The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM. The TA has been approved by the FERC.

Regional Transmission Organizations

OPCo is a member of PJM, a FERC-approved RTO.  RTOs operate, plan and control utility transmission assets to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.  AEP Texas is a member of ERCOT.

REGULATION

OPCo provides distribution and transmission services to retail customers within its service territory at cost-based rates approved by the PUCO or by the FERC.  AEP Texas provides transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules.  Transmission and distribution rates are established on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service.  The cost-of-service generally reflects operating expenses, including operation and maintenance expense, depreciation expense and taxes.  Utility commissions periodically adjust rates pursuant to a review of: (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.

FERC

The FERC regulates rates for transmission of electric power, accounting and other matters.  The FERC regulations require AEP to provide open access transmission service at FERC-approved rates, and it has approved cost-based formula transmission rates on file at the FERC.  The FERC also regulates unbundled transmission service to retail customers.  The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system.  The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. In addition, both the FERC and state regulators are permitted to review the books
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and records of any company within a holding company system. Additionally, the transmission and distribution utility subsidiaries are subject to reliability standards as set forth by the NERC, with the approval of the FERC.

SEASONALITY

The delivery of electric power is generally seasonal.  In many parts of the country, demand for power peaks during the hot summer months.  In other areas, power demand peaks during the winter months.  The pattern of this fluctuation may change due to the nature and location of AEP’s transmission and distribution facilities.  In addition, AEP transmission and distribution has historically delivered less power, and consequently earned less income, when weather conditions are milder.  In Texas, and to a lesser extent, in Ohio, where there is residential decoupling, unusually mild weather in the future could diminish AEP’s results of operations.  Conversely, unusually extreme weather conditions could increase AEP’s results of operations.

AEP TRANSMISSION HOLDCO

GENERAL

AEPTHCo is a holding company for (a) AEPTCo, which is the direct holding company for the State Transcos and (b) AEP’s Transmission Joint Ventures.

AEPTCo

AEPTCo wholly owns the State Transcos which are independent of, but respectively overlay, the following AEP electric utility operating companies: APCo, I&M, KPCo, OPCo, PSO, SWEPCo, and WPCo. The State Transcos develop, own, operate, and maintain their respective transmission assets. Assets of the State Transcos interconnect to transmission facilities owned by the aforementioned operating companies and nonaffiliated transmission owners within the footprints of PJM, MISO and SPP. APTCo, IMTCo, KTCo, OHTCo, and WVTCo are located within PJM. IMTCo also owns portions of the Greentown station assets located in MISO. OKTCo and SWTCo are located within SPP.

IMTCo, KTCo, OHTCo, OKTCo, and WVTCo own and operate transmission assets in their respective jurisdictions.  The Virginia SCC and WVPSC granted consent for APCo and APTCo to enter into a joint license agreement that will support APTCo investment in the state of Tennessee. SWTCo does not currently own or operate transmission assets.

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.  The State Transcos establish transmission rates each year through formula rate filings with the FERC.  The rate filings calculate the revenue requirement needed to cover the costs of operation and debt service and to earn an allowed ROE.  These rates are then included in an OATT for PJM, MISO and SPP.

The State Transcos own, operate, maintain and invest in transmission infrastructure in order to maintain and enhance system integrity and grid reliability, grid security, safety, reduce transmission constraints and facilitate interconnections of new generating resources and new wholesale customers, as well as enhance competitive wholesale electricity markets. A key part of AEP’s business is replacing and upgrading transmission facilities, assets and components of the existing AEP System as needed to maintain reliability.

The State Transcos provide the capability to build, replace and upgrade existing facilities. As of December 31, 2020, the State Transcos had $9.9 billion of transmission and other assets in-service with plans to construct approximately $4.2 billion of additional transmission assets through 2023. Additional investment in transmission infrastructure is needed within PJM and SPP to maintain the required level of grid reliability, resiliency, security and efficiency and to address an aging transmission infrastructure. Additional transmission facilities will be needed based on changes in generating resources, such as wind or solar projects, generation additions or retirements, and additional new customer interconnections.  The State Transcos will continue their investment to enhance physical and cyber security of assets, and are also investing in improving the telecommunication network that supports the operation and control of the grid.
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AEPTHCO JOINT VENTURE INITIATIVES

AEP has established joint ventures with other electric utility companies for the purpose of developing, building, and owning transmission assets that seek to improve reliability and market efficiency and provide transmission access to remote generation sources in North America (Transmission Joint Ventures).

The Transmission Joint Ventures currently include:

Joint Venture Name		Location		Projected or Actual Completion Date		Owners
(Ownership %)		Total Estimated/Actual Project Costs at Completion			Approved Return on Equity		
 								(in millions)					
ETT		Texas		(a)		Berkshire Hathaway		$	3,500.0 		(a)		9.6 	%		
 		(ERCOT) 		 		Energy (50%) 		 	 		 		
 		 		 		AEP (50%) 		 	 		 		
													
Prairie Wind		Kansas		2014		Evergy, Inc. (50%) 		158.0 				12.8 	%		
						Berkshire Hathaway Energy (25%)							
 		 		 		AEP (25%)  		 	 		 	 	
													
Pioneer		Indiana		2018		Duke Energy (50%) 		191.0 				10.52 	%	(b)	
 		 		 	 	AEP (50%) 		 	 		 	 	
													
Transource		Missouri		2016		Evergy, Inc. 		310.5 				11.1 	%	(c)	
Missouri		 		 	 	(13.5%) (d)		 	 		 	 	
 		 		 	 	AEP (86.5%) (d) 		 	 		 	 	
													
Transource		West		2019		Evergy, Inc.		84.0 				10.5 	%		
West Virginia		Virginia				(13.5%) (d) 							
						AEP (86.5%) (d) 							
													
Transource		Maryland		2023		Evergy, Inc.		20.9 		(e)		10.4 	%		
Maryland						(13.5%) (d)							
						AEP (86.5%) (d)							
													
Transource		Pennsylvania		2023		Evergy, Inc.		248.6 		(e)		10.4 	%		
Pennsylvania						(13.5%) (d)							
						AEP (86.5%) (d)							
													
Transource		Oklahoma		2026		Evergy, Inc.		112.6	(f)		10.3 	%		
Oklahoma						 (13.5%(d)							
						 AEP (86.5%) (d)							

(a)ETT is undertaking multiple projects and the completion dates will vary for those projects. ETT’s investment in completed and active projects in ERCOT is expected to be $3.5 billion.  Future projects will be evaluated on a case-by-case basis.
(b)In May 2020, Pioneer received FERC approval authorizing an ROE of 10.02% (10.52% inclusive of the RTO incentive adder of 0.5%).
(c)The ROE represents the weighted-average approved ROE based on the costs of two projects developed by Transource Missouri; the $64 million Iatan-Nashua project (10.3%) and the $247 million Sibley-Nebraska City project (11.3%).
(d)AEP owns 86.5% of Transource Missouri, Transource West Virginia, Transource Maryland, Transource Pennsylvania and Transource –Sooner-Wekiwa through its ownership interest in Transource Energy, LLC (Transource).  Transource is a joint venture with AEPTHCo and Evergy, Inc. formed to pursue competitive transmission projects.  AEPTHCo and Evergy, Inc. own 86.5% and 13.5% of Transource, respectively.
(e)In August 2016, Transource Maryland and Transource Pennsylvania received approval from the PJM Interconnection Board to construct portions of a transmission project located in both Maryland and Pennsylvania. The project is expected to go in-service in 2023. Project costs are in 2020 dollars.
(f)In 2016, Transource Kansas received approval from the FERC authorizing an ROE of 9.8% (10.3% inclusive of the RTO incentive adder of 0.5%) for future competitive transmission projects in SPP. In October 2020, Transource was awarded the Sooner-Wekiwa project by SPP and the project was assigned to Transource Kansas. In November 2020, Transource Kansas was renamed Transource Oklahoma. The project is expected to go in-service in 2026.

Transource Missouri, Transource West Virginia, Transource Maryland, Transource Pennsylvania and Transource Oklahoma are consolidated joint ventures by AEP.  All other joint ventures in the table above are not consolidated by AEP. AEP’s joint ventures do not have employees.  Business services for the joint ventures are provided by AEPSC and other AEP subsidiaries and the joint venture partners. During 2020, approximately 514 AEPSC employees and 271 operating company employees provided service to one or more joint ventures.

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REGULATION

The State Transcos and the Transmission Joint Ventures located outside of ERCOT establish transmission rates annually through forward-looking formula rate filings with the FERC pursuant to FERC-approved implementation protocols.  The protocols include a transparent, formal review process to ensure the updated transmission rates are prudently-incurred and reasonably calculated. The IMTCo-owned Greentown station assets acquired from Duke Energy Indiana, LLC in December 2018 are located in MISO. IMTCo utilizes a historic cost recovery model to recover MISO assets.

The State Transcos’ and the Transmission Joint Ventures’ (where applicable) rates are included in the respective OATT for PJM and SPP.  An OATT is the FERC rate schedule that provides the terms and conditions for transmission and related services on a transmission provider’s transmission system.  The FERC requires transmission providers such as PJM and SPP to offer transmission service to all eligible customers (for example, load-serving entities, power marketers, generators and customers) on a non-discriminatory basis.

The FERC-approved formula rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners in annual rate base filings with the FERC.  The formula rates establish rates for a one-year period based on the current projects in-service and proposed projects for a defined timeframe.  The formula rates also include a true-up calculation for the previous year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR.  PJM and SPP pay the transmission owners their ATRR for use of their facilities and bill transmission customers taking service under the PJM and SPP OATTs, based on the terms and conditions in the respective OATT for the service taken. Additionally, the State Transcos are subject to reliability standards promulgated by the NERC, with the approval of the FERC.

Management continues to monitor the FERC’s 2019 Notice of Inquiry regarding base ROE policy, the FERC’s 2020 Notice of Proposed Rulemaking regarding transmission incentives policy, and various other matters pending before the FERC with the potential to affect the transmission ROE methodology.

In the second quarter of 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 the second quarter of 2020, FERC Order 569A determined the base ROE for MISO’s transmission owning members, including AEP’s MISO transmission-owning subsidiaries, should be 10.02% (10.52% inclusive of the RTO incentive adder of 0.5%).

If the FERC makes any changes to its ROE and incentive policies, they 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.

In the annual rate base filings described above, the State Transcos in aggregate filed rate base totals of $7.0 billion, $5.9 billion and $4.6 billion for 2020, 2019 and 2018, respectively.  The total filed transmission revenue requirements, including prior year over/under-recovery of revenue and associated carrying charges were $1.2 billion, $992 million and $829 million for 2020, 2019, and 2018, respectively.

The rates of ETT, which is located in ERCOT, are determined by the PUCT.  ETT sets its rates through a combination of base rate cases and interim Transmission Cost of Services (TCOS) filings.  ETT may file interim TCOS filings semi-annually to update its rates to reflect changes in its net invested capital.

The Transmission Joint Ventures have approved ROEs ranging from 9.6% to 12.8% based on equity capital structures ranging from 40% to 60%.

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GENERATION & MARKETING

GENERAL

The AEP Generation & Marketing segment subsidiaries consist of a wholesale energy trading and marketing business, a retail supply and energy management business and competitive generating assets.  

AEP Energy Supply, LLC is a holding company with several divisions, including AEP Renewables and AEP OnSite Partners.

AEP Renewables develops, owns and operates utility scale renewable projects backed with long-term contracts with creditworthy counterparties throughout the United States.  AEP Renewables works directly with stakeholders to ensure that customers have clean, sustainable renewable energy to meet their environmental goals.  As of December 31, 2020, AEP Renewables owned projects operating in 11 states, including approximately 1,307 MWs of installed wind capacity and 90 MWs of installed solar capacity.  In October 2019, AEP Renewables entered into an agreement to construct Flat Ridge 3, a wind farm in Kansas.  The 128 MW facility is expected to reach commercial operation by May 2021. In November 2020, AEP Renewables signed a Purchase and Sale Agreement to acquire 75% of the Dry Lake Solar Project, a 100 MW solar facility in southern Nevada. This facility is expected to be in-service in the second quarter of 2021.

AEP OnSite Partners works directly with wholesale and large retail customers to provide tailored solutions to reduce their energy costs based upon market knowledge, innovative applications of technology and deal structuring capabilities.  AEP OnSite Partners targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions that create value for customers.  AEP OnSite Partners pursues and develops behind the meter projects with creditworthy customers.  As of December 31, 2020, AEP OnSite Partners owned projects located in 21 states, including approximately 152 MWs of installed solar capacity, and approximately 9 MWs of solar projects under construction.

With respect to the wholesale energy trading and marketing business, AEP Generation & Marketing segment subsidiaries enter into short-term and long-term transactions to buy or sell capacity, energy and ancillary services in ERCOT, SPP, MISO and PJM.  These subsidiaries sell power into the market and engage in power, natural gas and emissions allowances risk management and trading activities.  These activities primarily involve the purchase-and-sale of electricity (and to a lesser extent, natural gas and emissions allowances) under forward contracts at fixed and variable prices.  These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options.  The majority of forward contracts are typically settled by entering into offsetting contracts.  These transactions are executed with numerous counterparties or on exchanges.

With respect to the retail supply and energy management business, AEP Energy is a retail energy supplier that supplies electricity and/or natural gas to residential, commercial, and industrial customers.  AEP Energy provides various energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C.  AEP Energy had approximately 510,000 customer accounts as of December 31, 2020.

The primary fossil generation subsidiary in the Generation & Marketing segment is AGR.  As of December 31, 2020, AGR owns 643 MWs of generating capacity, almost all of which is operated by Buckeye Power, a nonaffiliated electric cooperative. Other subsidiaries in this segment own or have the right to receive power from additional generation assets. See Item 2 – Properties for more information regarding the generation assets of the Generation & Marketing segment. AGR is a competitive generation subsidiary.

REGULATION

AGR is a public utility under the Federal Power Act, and is subject to the FERC’s exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, the FERC has the authority to grant or deny market-based rates for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable.  The FERC granted AGR market-based rate authority in December 2013.  The FERC’s jurisdiction over rate-making also includes the authority to suspend the
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market-based rates of AGR and set cost-based rates if the FERC subsequently determines that it can exercise market power, create barriers to entry or engage in abusive affiliate transactions.  Periodically, AGR is required to file a market power update to show that it continues to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether it continues to qualify for market-based rates.  Other matters subject to the FERC jurisdiction include, but are not limited to, review of mergers, and dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility.

Specific operations of AGR are also subject to the jurisdiction of various other federal, state, regional and local agencies, including federal and state environmental protection agencies.  AGR is also regulated by the PUCT for transactions inside ERCOT.  Additionally, AGR is subject to mandatory reliability standards promulgated by the NERC, with the approval of the FERC.

COMPETITION

The AEP Generation & Marketing segment subsidiaries face competition for the sale of available power, capacity and ancillary services.  The principal factors of impact are electricity and fuel prices, new market entrants, construction or retirement of generating assets by others and technological advances in power generation. Because most of AGR’s remaining generation is coal-fired, lower relative natural gas prices will favor competitors that have a higher concentration of natural gas fueled generation.  Other factors impacting competitiveness include environmental regulation, transmission congestion or transportation constraints at or near generation facilities, inoperability or inefficiencies, outages and deactivations and retirements at generation facilities.

Technology advancements, increased demand for clean energy, changing consumer behaviors, low-priced and abundant natural gas, and regulatory and public policy reforms are among the catalysts for transformation within the industry that impact competition for AEP’s Generation & Marketing segment. AGR also competes with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas.  The primary factors in such competition are price, unit availability and the capability of customers to utilize sources of energy other than electric power.

Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production.  The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AGR’s competitiveness. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive.

This segment’s retail operations provide competitive electricity and natural gas in deregulated retail energy markets in six states and Washington, D.C. Each such retail choice jurisdiction establishes its own laws and regulations governing its competitive market, and public utility commission communications and utility default service pricing can affect customer participation in retail competition. Sustained low natural gas and power prices, low market volatility and maturing competitive environments can adversely affect this business.

This segment also engages in procuring and selling output from renewable generation sources under long-term contracts to creditworthy counterparties.  New sources are not acquired without first securing a long-term placement of such power.  Existing sources do not face competitive exposure.  Competitive nonaffiliated suppliers of renewable or other generation could limit opportunities for future transactions for new sources and related output contracts.

SEASONALITY

The consumption of electric power is generally seasonal.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In other areas, power demand peaks during the winter months.  The pattern of this fluctuation may change.
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Fuel Supply

The following table shows the generation sources by type, on an actual net generation (MWhs) basis, used by the Generation & Marketing segment, not including AEP Energy Partners’ offtake agreement from the Oklaunion Power Station which was retired in September 2020:

	2020		2019		2018	
Coal	46%		64%		88%	
	
Renewables	54%		36%		12%	

Coal and Consumables

AGR procures coal and consumables needed to burn the coal under a combination of purchasing arrangements including long-term and spot contracts with various producers and coal trading firms.  As contracts expire, they are replaced, as needed, with contracts at market prices. Coal and consumable inventories remain adequate to meet generation requirements.

Management believes that AGR will be able to secure and transport coal and consumables of adequate quality and in adequate quantities to operate its coal-fired unit.  AGR, through its contracts with third-party transporters, has the ability to adequately move and store coal and consumables for use in its generating facility. AGR plants consumed 1.6 million tons of coal in 2020.

The coal supplies at AGR’s plant vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, coal quality, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. AGR aims to maintain the coal inventory of its managed plant in the range of 20 to 60 days of full load burn.  As of December 31, 2020, the coal inventory of AGR was within the target range.

Counterparty Risk Management

Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions.  As of December 31, 2020, counterparties posted approximately $29 million in cash, cash equivalents or letters of credit with AEP for the benefit of AEP’s Generation & Marketing segment subsidiaries (while, as of that date, AEP’s Generation & Marketing segment subsidiaries posted approximately $122 million with counterparties and exchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily.  See the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

Certain Power Agreements

As of December 31, 2020, the assets utilized in this segment included approximately 1,307 MWs of company-owned domestic wind power facilities and 101 MWs of domestic wind power from long-term purchase power agreements. Additional long term purchased power agreements have been entered into for 712 MWs of wind and 200 MWs of solar capacity which are all under construction. These agreements are all contingent on completion of construction which is expected by the end of 2022. An agreement which transferred 355 MWs of coal-fired capacity from the Oklaunion Power Station to this segment was terminated upon the closure of the facility in October.
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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following persons are executive officers of AEP.  Their ages are given as of February 25, 2021.  The officers are appointed annually for a one-year term by the board of directors of AEP.

Nicholas K. Akins
Chairman of the Board, President and Chief Executive Officer
Age 60
Chairman of the Board since January 2014, President since January 2011 and Chief Executive Officer since November 2011.

Lisa M. Barton
Executive Vice President and Chief Operating Officer
Age 55
Executive Vice President - Utilities from January 2019 to December 2020, Executive Vice President - Transmission from August 2011 to December 2018.

Paul Chodak, III
Executive Vice President - Generation
Age 57
Executive Vice President - Utilities from January 2017 to December 2018. President and Chief Operating Officer of I&M from July 2010 to December 2016.

David M. Feinberg
Executive Vice President, General Counsel and Secretary
Age 51
Executive Vice President since January 2013.

Lana L. Hillebrand (Retired in 2020)
Executive Vice President and Chief Administrative Officer
Age 60
Chief Administrative Officer since December 2012 and Senior Vice President from December 2012 to December 2016.

Mark C. McCullough
Executive Vice President - Energy Delivery
Age 61
Executive Vice President - Transmission from January 2019 to December 2020, Executive Vice President - Generation from January 2011 to December 2018.

Charles R. Patton
Executive Vice President - External Affairs
Age 61
Executive Vice President - External Affairs since January 2017. President and Chief Operating Officer of APCo from June 2010 to December 2016.

Julia A. Sloat
Executive Vice President and Chief Financial Officer
Age 51
Senior Vice President, Treasury & Risk and Treasurer from January 2019 to December 2020. President and Chief Operating Officer of OPCo from May 2016 to December 2018.

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Brian X. Tierney
Executive Vice President - Strategy
Age 53
Executive Vice President and Chief Financial Officer from October 2009 to December 2020.

Charles E. Zebula
Executive Vice President - Energy Supply
Age 60
Executive Vice President - Energy Supply since January 2013.
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ITEM 1A.   RISK FACTORS

GENERAL RISKS OF REGULATED OPERATIONS

AEP may not be able to recover the costs of substantial planned investment in capital improvements and additions. (Applies to all Registrants)

AEP’s business plan calls for extensive investment in capital improvements and additions, including the construction of additional transmission facilities, modernizing existing infrastructure, installation of environmental upgrades and retrofits as well as other initiatives.  AEP’s public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions.  If these regulatory commissions do not approve adjustments to the rates charged, affected AEP subsidiaries would not be able to recover the costs associated with their investments.  This would cause financial results to be diminished.

Regulated electric revenues and earnings are dependent on federal and state regulation that may limit AEP’s ability to recover costs and other amounts. (Applies to all Registrants)

The rates customers pay to AEP regulated utility businesses are subject to approval by the FERC and the respective state utility commissions of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. In certain instances, AEP’s applicable regulated utility businesses may agree to negotiated settlements related to various rate matters that are subject to regulatory approval. AEP cannot predict the ultimate outcomes of any settlements or the actions by the FERC or the respective state commissions in establishing rates.

If regulated utility earnings exceed the returns established by the relevant commissions, retail electric rates may be subject to review and possible reduction by the commissions, which may decrease future earnings. Additionally, if regulatory bodies do not allow recovery of costs incurred in providing service on a timely basis, it could reduce future net income and cash flows and negatively impact financial condition. Similarly, if recovery or other rate relief authorized in the past is overturned or reversed on appeal, future earnings could be negatively impacted. Any regulatory action or litigation outcome that triggers a reversal of a regulatory asset or deferred cost generally results in an impairment to the balance sheet and a charge to the income statement of the company involved. See Note 4 – Rate Matters included in the 2020 Annual Report for additional information.

AEP’s transmission investment strategy and execution are dependent on federal and state regulatory policy. (Applies to all Registrants)

A significant portion of AEP’s earnings is derived from transmission investments and activities.  FERC policy currently favors the expansion and updating of the transmission infrastructure within its jurisdiction.  If the FERC were to adopt a different policy, if states were to limit or restrict such policies, or if transmission needs do not continue or develop as projected, AEP’s strategy of investing in transmission could be impacted.  Management believes AEP’s experience with transmission facilities construction and operation gives AEP an advantage over other competitors in securing authorization to install, construct and operate new transmission lines and facilities.  However, there can be no assurance that PJM, SPP, ERCOT or other RTOs will authorize new transmission projects or will award such projects to AEP.  

Certain elements of AEP’s transmission formula rates have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on AEP’s business, financial condition, results of operations and cash flows. (Applies to all Registrants other than AEP Texas)

AEP provides transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by AEP to calculate its respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of AEP’s rates accepted or approved by the FERC, including the formula rate templates, the rates of return on the
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actual equity portion of its respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative. In addition, interested parties may challenge the annual implementation and calculation by AEP of its projected rates and formula rate true-up pursuant to its approved formula rate templates under AEP’s formula rate implementation protocols. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC can make appropriate prospective adjustments to them and/or disallow any of AEP’s inclusion of those aspects in the rate setting formula.

AEP settled challenges to its SPP and PJM formula rates in proceedings at the FERC in 2019.  However, inquiries related to rates of return, as well as challenges to the formula rates of other utilities, are ongoing in other proceedings at the FERC.  The results of these proceedings could potentially negatively impact AEP in any future challenges to AEP’s formula rates.  If the FERC orders revenue reductions, including refunds, in any future cases related to its formula rates, it could reduce future net income and cash flows and impact financial condition.

End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to AEP, particularly if rates for delivered electricity increase substantially.

AEP faces risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede their development and operating activities. (Applies to all Registrants)

AEP owns, develops, constructs, manages and operates electric generation, transmission and distribution facilities. A key component of AEP's growth is its ability to construct and operate these facilities. As part of these operations AEP must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. Should AEP be unsuccessful in obtaining necessary licenses or permits on acceptable terms or resolving third-party challenges to such licenses or permits, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances, it could reduce future net income and cash flows and impact financial condition. Any failure to negotiate successful project development agreements for new facilities with third-parties could have similar results.

Changes in technology and regulatory policies may lower the value of electric utility facilities and franchises. (Applies to all Registrants)

AEP primarily generates electricity at large central facilities and delivers that electricity to customers over its transmission and distribution facilities to customers usually situated within an exclusive franchise. This method results in economies of scale and generally lower costs than newer technologies such as fuel cells and microturbines, and distributed generation using either new or existing technology.  Other technologies, such as light emitting diodes (LEDs), increase the efficiency of electricity and, as a result, lower the demand for it.   Changes in regulatory policies and advances in batteries or energy storage, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production and delivery.  These developments can challenge AEP’s competitive ability to maintain relatively low cost, efficient and reliable operations, to establish fair regulatory mechanisms and to provide cost-effective programs and services to customers.  Further, in the event that alternative generation resources are mandated, subsidized or encouraged through legislation or regulation or otherwise are economically competitive and added to the available generation supply, such resources could displace a higher marginal cost generating units, which could reduce the price at which market participants sell their electricity.

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AEP may not recover costs incurred to begin construction on projects that are canceled. (Applies to all Registrants)

AEP’s business plan for the construction of new projects involves a number of risks, including construction delays, non-performance by equipment and other third-party suppliers, and increases in equipment and labor costs.  To limit the risks of these construction projects, AEP’s subsidiaries enter into equipment purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals and/or siting or environmental permits.  If any of these projects are canceled for any reason, including failure to receive necessary regulatory approvals and/or siting or environmental permits, significant cancellation penalties under the equipment purchase orders and construction contracts could occur.  In addition, if any construction work or investments have been recorded as an asset, an impairment may need to be recorded in the event the project is canceled.

AEP is exposed to nuclear generation risk. (Applies to AEP and I&M)

I&M owns the Cook Plant, which consists of two nuclear generating units for a rated capacity of 2,288 MWs, or about 7% of the generating capacity in the AEP System.  AEP and I&M are, therefore, subject to the risks of nuclear generation, which include the following:

•The potential harmful effects on the environment and human health due to an adverse incident/event resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as SNF.
•Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations.
•Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance and potentially contribute to the coverage for losses of others).
•Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if these risks are triggered.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities.  In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved.  Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants.  In addition, although management has no reason to anticipate a serious nuclear incident at the Cook Plant, if an incident did occur, it could harm results of operations or financial condition.  A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.  Moreover, a major incident at any nuclear facility in the U.S. could require AEP or I&M to make material contributory payments.

Costs associated with the operation (including fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the operation of nuclear facilities.  Costs also may include replacement power, any unamortized investment at the end of the useful life of the Cook Plant (whether scheduled or premature), the carrying costs of that investment and retirement costs.  The ability to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.

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AEP subsidiaries are exposed to risks through participation in the market and transmission structures in various regional power markets that are beyond their control. (Applies to all Registrants)

Results are likely to be affected by differences in the market and transmission structures in various regional power markets.  The rules governing the various RTOs, including SPP and PJM, may also change from time to time which could affect costs or revenues.  Existing, new or changed rules of these RTOs could result in significant additional fees and increased costs to participate in those structures, including the cost of transmission facilities built by others due to changes in transmission rate design. In addition, these RTOs may assess costs resulting from improved transmission reliability, reduced transmission congestion and firm transmission rights. As members of these RTOs, AEP’s subsidiaries are subject to certain additional risks, including the allocation among existing members, of losses caused by unreimbursed defaults of other participants in these markets and resolution of complaint cases that may seek refunds of revenues previously earned by members of these markets.

AEP could be subject to higher costs and/or penalties related to mandatory reliability standards. (Applies to all Registrants)

Owners and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC.  The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles.  Compliance with new reliability standards may subject AEP to higher operating costs and/or increased capital expenditures.  While management expects to recover costs and expenditures from customers through regulated rates, there can be no assurance that the applicable commissions will approve full recovery in a timely manner.  If AEP were found not to be in compliance with the mandatory reliability standards, AEP could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.

A substantial portion of the receivables of AEP Texas is concentrated in a small number of REPs, and any delay or default in payment could adversely affect its cash flows, financial condition and results of operations. (Applies to AEP and AEP Texas)

AEP Texas collects receivables from the distribution of electricity from REPs that supply the electricity it distributes to its customers. As of December 31, 2020, AEP Texas did business with approximately 122 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for these services or could cause them to delay such payments. AEP Texas depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which AEP Texas can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and AEP Texas thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. In 2020, AEP Texas’ three largest REPs accounted for 46% of its operating revenue. Any delay or default in payment by REPs could adversely affect cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments AEP Texas had received from such REP.

Ohio House Bill 6 (HB 6), which provides for beneficial cost recovery for OPCo and for plants owned by OVEC, has come under public scrutiny. (Applies to AEP and OPCo)

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts, OVEC’s coal-fired generating units and energy efficiency measures. AEP and OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB
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6. The outcome of the U.S. Attorney’s Office investigation and its impact on HB 6 is not known. If the provisions of HB 6 were to be eliminated, it is unclear whether new legislation addressing similar issues would be adopted. To the extent that OPCo is unable to recover the costs currently authorized by HB 6, it could reduce future net income and cash flows and impact financial condition. In addition, the impact of continued public scrutiny of HB 6 is not known, and may have an adverse impact on AEP and OPCo, including their relationship with regulatory and legislative authorities, customers and other stakeholders. AEP is a defendant in current litigation relating to HB6 and AEP or OPCo may be involved in future litigation.

RISKS RELATED TO MARKET, ECONOMIC OR FINANCIAL VOLATILITY AND OTHER RISKS

AEP’s financial condition and results of operations could continue to be adversely affected by the ongoing Coronavirus pandemic. (Applies to all Registrants)

The global 2019 novel coronavirus pandemic is an evolving situation that could lead to extended disruption of economic activity in AEP’s markets. COVID-19 could negatively affect AEP’s ability to operate its generating and transmission and distribution assets, its ability to access capital markets, and results of operations. AEP currently cannot estimate the potential impact to its financial position, results of operations and cash flows caused by COVID-19, which will depend on future developments and which are highly uncertain at this time. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview for additional information on COVID-19.

AEP’s financial performance may be adversely affected if AEP is unable to successfully operate facilities or perform certain corporate functions. (Applies to all Registrants)

Performance is highly dependent on the successful operation of generation, transmission and/or distribution facilities.  Operating these facilities involves many risks, including:

•Operator error and breakdown or failure of equipment or processes.
•Operating limitations that may be imposed by environmental or other regulatory requirements.
•Labor disputes.
•Compliance with mandatory reliability standards, including mandatory cyber security standards.
•Information technology failure that impairs AEP’s information technology infrastructure or disrupts normal business operations.
•Information technology failure that affects AEP’s ability to access customer information or causes loss of confidential or proprietary data that materially and adversely affects AEP’s reputation or exposes AEP to legal claims.
•Fuel or water supply interruptions caused by transportation constraints, adverse weather such as drought, non-performance by suppliers and other factors.
•Catastrophic events such as fires, earthquakes, explosions, hurricanes, tornados, ice storms, terrorism (including cyber-terrorism), floods or other similar occurrences.
•Fuel costs and related requirements triggered by financial stress in the coal industry.

Physical attacks or hostile cyber intrusions could severely impair operations, lead to the disclosure of confidential information and damage AEP’s reputation. (Applies to all Registrants)

AEP and its regulated utility businesses face physical security and cybersecurity risks as the owner-operators of generation, transmission and/or distribution facilities and as participants in commodities trading. AEP and its regulated utility businesses own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run these facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or AEP operations could view these computer systems, software or networks as targets for cyber-attack.  In addition, the electric utility business requires the collection of sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.
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A security breach of AEP or its regulated utility businesses’ physical assets or information systems, interconnected entities in RTOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system. AEP and its regulated utility businesses could be subject to financial harm associated with theft or inappropriate release of certain types of information, including sensitive customer, vendor, employee, trading or other confidential data. A successful cyber-attack on the systems that control generation, transmission, distribution or other assets could severely disrupt business operations, preventing service to customers or collection of revenues. The breach of certain business systems could affect the ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to AEP’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring.  For these reasons, a significant cyber incident could reduce future net income and cash flows and negatively impact financial condition.

If AEP is unable to access capital markets or insurance markets on reasonable terms, it could reduce future net income and cash flows and negatively impact financial condition. (Applies to all Registrants)

AEP relies on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows; AEP also relies on access to insurance markets to assist in managing its risk and liability profile. Volatility, increased interest rates and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness. Certain sources of insurance and debt and equity capital have expressed increasing unwillingness to procure insurance for or to invest in companies, such as AEP, that rely on fossil fuels. If sources of capital for AEP are reduced, capital costs could increase materially. Restricted access to capital or insurance markets and/or increased borrowing costs or insurance premiums could reduce future net income and cash flows and negatively impact financial condition.

Shareholder activism could cause AEP to incur significant expense, hinder execution of AEP’s business strategy and impact AEP’s stock price. (Applies to all Registrants)

Shareholder activism, which can take many forms and arise in a variety of situations, could result in substantial costs and divert management’s and AEP’s board’s attention and resources from AEP’s business. Additionally, such shareholder activism could give rise to perceived uncertainties as to AEP’s future, adversely affect AEP’s relationships with its employees, customers or service providers and make it more difficult to attract and retain qualified personnel. Also, AEP may be required to incur significant fees and other expenses related to activist shareholder matters, including for third-party advisors. AEP’s stock price could be subject to significant fluctuation or otherwise be adversely affected by the events, risks and uncertainties of any shareholder activism.

The announced phasing out of LIBOR after 2021 may adversely affect the costs and availability of financing. (Applies to all Registrants)

A portion of the Registrants’ indebtedness bears interest at fluctuating interest rates, primarily based on the London interbank offered rate (“LIBOR”) for deposits of U.S. dollars. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. Subsequently, on November 30, 2020, the Federal Reserve and the Financial Conduct Authority in the United Kingdom announced that LIBOR would be phased out completely by June 20, 2023 and replaced by the Secured Overnight Financing Rate ("SOFR"). While this announcement extends the transition period to June 2023, the United States Federal Reserve concurrently issued a statement advising banks to stop new U.S. dollar LIBOR issuances by the end of 2021. However, because SOFR is a broad U.S. Treasury repo financing rate that represents overnight secured funding transactions, it differs fundamentally from U.S. dollar LIBOR. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such phase-out and alternative reference rates or disruption in the financial market could cause interest rates to increase. If sources of capital for the Registrants are reduced, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could reduce future net income and cash flows and negatively impact financial condition and/or liquidity.
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Downgrades in AEP’s credit ratings could negatively affect its ability to access capital. (Applies to all Registrants)

The credit ratings agencies periodically review AEP’s capital structure and the quality and stability of earnings and cash flows.  Any negative ratings actions could constrain the capital available to AEP and could limit access to funding for operations.  AEP’s business is capital intensive, and AEP is dependent upon the ability to access capital at rates and on terms management determines to be attractive.  If AEP’s ability to access capital becomes significantly constrained, AEP’s interest costs will likely increase and could reduce future net income and cash flows and negatively impact financial condition.

AEP and AEPTCo have no income or cash flow apart from dividends paid or other payments due from their subsidiaries. (Applies to AEP and AEPTCo)

AEP and AEPTCo are holding companies and have no operations of their own.  Their ability to meet their financial obligations associated with their indebtedness and to pay dividends is primarily dependent on the earnings and cash flows of their operating subsidiaries, primarily their regulated utilities, and the ability of their subsidiaries to pay dividends to, or repay loans from them.  Their subsidiaries are separate and distinct legal entities that have no obligation (apart from loans from AEP or AEPTCo) to provide them with funds for their payment obligations, whether by dividends, distributions or other payments.  Payments to AEP or AEPTCo by their subsidiaries are also contingent upon their earnings and business considerations.  AEP and AEPTCo indebtedness and dividends are structurally subordinated to all subsidiary indebtedness.

AEP’s operating results may fluctuate on a seasonal or quarterly basis and with general economic and weather conditions. (Applies to all Registrants)

Electric power consumption is generally seasonal.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In other areas, power demand peaks during the winter.  As a result, overall operating results in the future may fluctuate substantially on a seasonal basis.  In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder.  Unusually mild weather in the future could reduce future net income and cash flows and negatively impact financial condition.  In addition, unusually extreme weather conditions could impact AEP’s results of operations in a manner that would not likely be sustainable.

Further, deteriorating economic conditions triggered by any cause, including international tariffs, generally result in reduced consumption by customers, particularly industrial customers who may curtail operations or cease production entirely, while an expanding economic environment generally results in increased revenues.  As a result, prevailing economic conditions may reduce future net income and cash flows and negatively impact financial condition.

Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and the costs of nuclear decommissioning. (Applies to all Registrants and to AEP and I&M with respect to the costs of nuclear decommissioning)

The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, future government regulation, changes in life expectancy, and the frequency and amount of AEP’s required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and AEP could be required from time to time to fund the pension plan with significant amounts of cash. Such cash funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations.

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Additionally, I&M holds a significant amount of assets in its nuclear decommissioning trusts to satisfy obligations to decommission its nuclear plant. The rate of return on assets held in those trusts can significantly impact both the costs of decommissioning and the funding requirements for the trusts.

AEP’s results of operations and cash flows may be negatively affected by a lack of growth or slower growth in the number of customers, or decline in customer demand. (Applies to all Registrants)

Growth in customer accounts and growth of customer usage each directly influence demand for electricity and the need for additional power generation and delivery facilities.  Customer growth and customer usage are affected by a number of factors outside the control of AEP, such as mandated energy efficiency measures, demand-side management goals, distributed generation resources and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity.

Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to further reduce energy consumption.  Additionally, technological advances or other improvements in or applications of technology could lead to declines in per capita energy consumption.  Some or all of these factors, could impact the demand for electricity.

Failure to attract and retain an appropriately qualified workforce could harm results of operations. (Applies to all Registrants)

Certain events, such as an aging workforce without appropriate replacements, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs.  The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development.  In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise.  Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business.  If AEP is unable to successfully attract and retain an appropriately qualified workforce, future net income and cash flows may be reduced.

Changes in the price of commodities, the cost of procuring fuel, emission allowances for criteria pollutants and the costs of transport may increase AEP’s cost of producing power, impacting financial performance. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

AEP is exposed to changes in the price and availability of fuel (including the cost to procure coal and gas) and the price and availability to transport fuel.  AEP has existing contracts of varying durations for the supply of fuel, but as these contracts end or if they are not honored, AEP may not be able to purchase fuel on terms as favorable as the current contracts.  The inability to procure fuel at costs that are economical could cause AEP to retire generating capacity prior to the end of its useful life, and while AEP typically recovers expenditures for undepreciated plant balances, there can be no assurance in the future that AEP will recover such costs. Similarly, AEP is exposed to changes in the price and availability of emission allowances.  AEP uses emission allowances based on the amount of fuel used and reductions achieved through emission controls and other measures.  Based on current environmental programs remaining in effect, AEP has sufficient emission allowances to cover the majority of the projected needs for the next two years and beyond.  If the Federal EPA attempts to further reduce interstate transport, and it is acceptable by the courts, additional costs may be incurred either to acquire additional allowances or to achieve further reductions in emissions.  If AEP needs to obtain allowances, those purchases may not be on as favorable terms as those under the current environmental programs.  AEP’s risks relative to the price and availability to transport coal include the volatility of the price of diesel which is the primary fuel used in transporting coal by barge.

Prices for coal, natural gas and emission allowances have shown material swings in the past.  Changes in the cost of fuel, emission allowances or natural gas and changes in the relationship between such costs and the market prices of power could reduce future net income and cash flows and negatively impact financial condition.
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In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value trading and marketing transactions, and those differences may be material.  As a result, as those transactions are marked-to-market, they may impact future results of operations and cash flows and impact financial condition.

AEP is subject to physical and financial risks associated with climate change. (Applies to all Registrants)

Climate change creates physical and financial risk.  Physical risks from climate change may include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events, such as fires.  Customers’ energy needs vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling represent their largest energy use.  To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require AEP to invest in additional generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect financial condition through decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions.  Weather conditions outside of the AEP service territory could also have an impact on revenues.  AEP buys and sells electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on AEP’s own and/or other systems may raise electricity prices as AEP buys short-term energy to serve AEP’s own system, which would increase the cost of energy AEP provides to customers.

Severe weather and weather-related events impact AEP’s service territories, primarily when thunderstorms, tornadoes, hurricanes, fires, floods and snow or ice storms occur.  To the extent the frequency and intensity of extreme weather events and storms increase, AEP’s cost of providing service will increase, including the costs and the availability of procuring insurance related to such impacts, and these costs may not be recoverable.  Changes in precipitation resulting in droughts, water shortages or floods could adversely affect operations, principally the fossil fuel generating units.  A negative impact to water supplies due to long-term drought conditions or severe flooding could adversely impact AEP’s ability to provide electricity to customers, as well as increase the price they pay for energy.  AEP may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact revenues.  AEP’s financial performance is tied to the health of the regional economies AEP serves.  The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of the communities within the AEP System.

Management cannot predict the outcome of the legal proceedings relating to AEP’s business activities. (Applies to all Registrants)

AEP is involved in legal proceedings, claims and litigation arising out of its business operations, the most significant of which are summarized in Note 6 - Commitments, Guarantees and Contingencies included in the 2020 Annual Report.  Adverse outcomes in these proceedings could require significant expenditures that could reduce future net income and cash flows and negatively impact financial condition.

Disruptions at power generation facilities owned by third-parties could interrupt the sales of transmission and distribution services. (Applies to AEP and AEP Texas)

AEP Texas transmits and distributes electric power that the REPs obtain from power generation facilities owned by third-parties. If power generation is disrupted or if power generation capacity is inadequate, sales of transmission and distribution services may be diminished or interrupted, and results of operations, financial condition and cash flows could be adversely affected.

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Management is unable to predict the course, results or impact, if any, of current or future litigation or investigations relating to the extreme winter weather in Texas in February 2021. (Applies to AEP and AEP Texas)

As a result of the February 2021 severe winter weather in Texas which caused a shortage of electric generation, ERCOT instructed AEP Texas and other Texas electric utilities to initiate power outages to avoid a sustained large-scale outage and prevent long-term damage to the electric system. At its peak, approximately 468,000 (44%) AEP Texas customers were without power.

In February 2021, a lawsuit was filed in Nueces, Texas County Court against AEP and AEP Texas alleging the failure to exercise reasonable care in maintaining and updating its generation, transmission and distribution facilities in order to prevent cold weather failures and other related negligence. The complaint seeks monetary damages among other forms of relief.

In February 2021, AEP Texas received a Civil Investigative Demand from the Office of the Attorney General of Texas requesting, among other data, information about its communications to and from ERCOT, PUCT, retail electric providers, utilities, or power generation companies, concerning power outages related to the February 2021 winter storm. The company intends to respond to the Civil Investigative Demand.

Management is unable to predict the course or outcome of these or any future litigation or investigations or their impact, if any, on future results of operations, financial condition and cash flows.

Hazards associated with high-voltage electricity transmission may result in suspension of AEP’s operations or the imposition of civil or criminal penalties. (Applies to all Registrants)

AEP operations are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, inclement weather, natural disasters, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. The hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. AEP maintains property and casualty insurance, but AEP is not fully insured against all potential hazards incident to AEP’s business, such as damage to poles, towers and lines or losses caused by outages.

AEPTCo depends on its affiliates in the AEP System for a substantial portion of its revenues. (Applies to AEPTCo)

AEPTCo’s principal transmission service customers are its affiliates in the AEP System. Management expects that these affiliates will continue to be AEPTCo’s principal transmission service customers for the foreseeable future. For the year ended December 31, 2020, its affiliates were responsible for approximately 78% of the consolidated transmission revenues of AEPTCo.

Most of the real property rights on which the assets of AEPTCo are situated result from affiliate license agreements and are dependent on the terms of the underlying easements and other rights of its affiliates. (Applies to AEPTCo)

AEPTCo does not hold title to the majority of real property on which its electric transmission assets are located. Instead, under the provisions of certain affiliate contracts, it is permitted to occupy and maintain its facilities upon real property held by the respective AEP System utility affiliate that overlay its operations. The ability of AEPTCo to continue to occupy such real property is dependent upon the terms of such affiliate contracts and upon the underlying real property rights of these utility affiliates, which may be encumbered by easements, mineral rights and other similar encumbrances that may affect the use of such real property. AEP can give no assurance that (a) the
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relevant AEP System utility affiliates will continue to be affiliates of AEPTCo, (b) suitable replacement arrangements can be obtained in the event that the relevant AEP System utility affiliates are not its affiliates and (c) the underlying easements and other rights are sufficient to permit AEPTCo to operate its assets in a manner free from interruption.

RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Costs of compliance with existing environmental laws are significant. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

Operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety.  A majority of the electricity generated by the AEP System is produced by the combustion of fossil fuels.  Emissions of nitrogen and sulfur oxides, mercury and particulates and the discharge and disposal of solid waste (including coal-combustion residuals or CCR) resulting from fossil fueled generation plants are subject to increased regulations, controls and mitigation expenses.  Compliance with these legal requirements requires AEP to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees, disposal and permits at AEP facilities and could cause AEP to retire generating capacity prior to the end of its estimated useful life.  Costs of compliance with environmental statutes and regulations could reduce future net income and negatively impact financial condition, especially if emission, CCR waste and/or discharge obligations are tightened, more extensive operating and/or permitting requirements are imposed or additional substances become regulated.  Although AEP typically recovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs from customers, there can be no assurance in the future that AEP will recover the remaining costs associated with such plants.  Failure to recover these costs could reduce future net income and cash flows and possibly harm financial condition. 

Regulation of CO2 emissions could materially increase costs to AEP and its customers or cause some electric generating units to be uneconomical to operate or maintain. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

In 2014, the Federal EPA issued standards for new, modified and reconstructed units, and a guideline for the development of SIPs that would reduce carbon CO2 emissions from existing utility units (the Clean Power Plan). In 2019, the Federal EPA repealed the Clean Power Plan, and replaced it with new guidelines called the Affordable Clean Energy (ACE) rule. In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit vacated the ACE Rule and remanded it to the Federal EPA. The new administration has announced addressing climate change as a policy priority. Costs of compliance with the environmental regulation of CO2 emissions, if any, could reduce future net income and negatively impact financial condition and/or could cause AEP to retire generating capacity prior to the end of its estimated useful life. Although AEP typically recovers environmental expenditures, there can be no assurance in the future that AEP can recover such costs which could reduce future net income and cash flows and possibly harm financial condition.

Courts adjudicating nuisance and other similar claims in the future may order AEP to pay damages or to limit or reduce emissions. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

In the past, there have been several cases seeking damages based on allegations of federal and state common law nuisance in which AEP, among others, were defendants.  In general, the actions allege that emissions from the defendants’ power plants constitute a public nuisance.  The plaintiffs in these actions generally seek recovery of damages and other relief.  If future actions are resolved against AEP, substantial modifications or retirement of AEP’s existing coal-fired power plants could be required, and AEP might be required to purchase power from third-parties to fulfill AEP’s commitments to supply power to AEP customers.  This could have a material impact on revenues.  In addition, AEP could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations.  Unless recovered, those costs could reduce future net income and cash flows and harm financial condition.  Moreover, results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.
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Commodity trading and marketing activities are subject to inherent risks which can be reduced and controlled but not eliminated. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

AEP routinely has open trading positions in the market, within guidelines set by AEP, resulting from the management of AEP’s trading portfolio.  To the extent open trading positions exist, fluctuating commodity prices can improve or diminish financial results and financial position.

AEP’s power trading activities also expose AEP to risks of commodity price movements.  To the extent that AEP’s power trading does not hedge the price risk associated with the generation it owns, or controls, AEP would be exposed to the risk of rising and falling spot market prices.

In connection with these trading activities, AEP routinely enters into financial contracts, including futures and options, OTC options, financially-settled swaps and other derivative contracts.  These activities expose AEP to risks from price movements.  If the values of the financial contracts change in a manner AEP does not anticipate, it could harm financial position or reduce the financial contribution of trading operations.

Parties with whom AEP has contracts may fail to perform their obligations, which could harm AEP’s results of operations. (Applies to all Registrants)

AEP sells power from its generation facilities into the spot market and other competitive power markets on a contractual basis. AEP also enters into contracts to purchase and sell electricity, natural gas, emission allowances and coal as part of its power marketing and energy trading operations. AEP is exposed to the risk that counterparties that owe AEP money or the delivery of a commodity, including power, could breach their obligations.  Should the counterparties to these arrangements fail to perform, AEP may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed AEP’s contractual prices, which would cause financial results to be diminished and AEP might incur losses.  Although estimates take into account the expected probability of default by a counterparty, actual exposure to a default by a counterparty may be greater than the estimates predict.

AEP relies on electric transmission facilities that AEP does not own or control.  If these facilities do not provide AEP with adequate transmission capacity, AEP may not be able to deliver wholesale electric power to the purchasers of AEP’s power. (Applies to all Registrants)

AEP depends on transmission facilities owned and operated by other nonaffiliated power companies to deliver the power AEP sells at wholesale.  This dependence exposes AEP to a variety of risks.  If transmission is disrupted, or transmission capacity is inadequate, AEP may not be able to sell and deliver AEP wholesale power.  If a region’s power transmission infrastructure is inadequate, AEP’s recovery of wholesale costs and profits may be limited.  If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales.  Although these initiatives are designed to encourage wholesale market transactions, access to transmission systems may not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable.  Management also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

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OVEC may require additional liquidity and other capital support.  (Applies to AEP, APCo, I&M and OPCo)

AEP and several nonaffiliated utility companies, including Energy Harbor (formerly FirstEnergy Solutions), a nonaffiliated party, own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it. Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. As of December 31, 2020, OVEC has outstanding indebtedness of approximately $1.3 billion, of which APCo, I&M, and OPCo are collectively responsible for $555 million through the ICPA. Although they are not an obligor or guarantor, APCo, I&M, and OPCo are responsible for their respective ratio of OVEC’s outstanding debt through the ICPA.

The aggregate power participation ratio of Energy Harbor under the ICPA is 4.85%. A portion of Energy Harbor’s revenues includes amounts authorized under HB 6. The PUCO has rescinded its prior authorization of certain HB 6 related recovery for eligible entities including Energy Harbor. If these amounts are not collected or if HB 6 is repealed and not replaced, Energy Harbor’s financial ability to participate in the ICPA could be adversely impacted. Management is currently unable to predict the outcome of the issues related to HB 6 and will continue to monitor the regulatory and legislative process and any potential impact to OVEC’s cash flows or financial condition. If OVEC does not have sufficient funds to honor its payment obligations, there is risk that APCo, I&M and/or OPCo may need to make payments in addition to their power participation ratio payments. Further, if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%.

ITEM 1B.   UNRESOLVED STAFF COMMENTS

None.

ITEM 2.   PROPERTIES

GENERATION FACILITIES

As of December 31, 2020, the AEP System owned (or leased where indicated) generation plants, with locations and net maximum power capabilities (winter rating), are shown in the following tables:

Vertically Integrated Utilities Segment

AEGCo		 		 		 		 		 	
Plant Name		Units		State		Fuel Type		Net Maximum
Capacity (MWs)		Year Plant
or First Unit Commissioned	
Rockport, Units 1 and 2 – 50% of each (a)		2		IN		Steam - Coal		1,310 			1984	

(a)Rockport Plant, Unit 2 is leased.

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APCo		 		 		 		 		 	
Plant Name		Units		State		Fuel Type		Net Maximum
Capacity (MWs)		Year Plant
or First Unit Commissioned	
Buck		3		VA		Hydro		11 			1912	
Byllesby		4		VA		Hydro		19 			1912	
Claytor		4		VA		Hydro		75 			1939	
Leesville		2		VA		Hydro		50 			1964	
London		3		WV		Hydro		14 			1935	
Marmet		3		WV		Hydro		14 			1935	
Niagara		2		VA		Hydro		2 			1906	
Winfield		3		WV		Hydro		15 			1938	
Ceredo		6		WV		Natural Gas		516 			2001	
Dresden		3		OH		Natural Gas		613 			2012	
Smith Mountain		5		VA		Pumped Storage		585 			1965	
Amos		3		WV		Steam - Coal		2,930 			1971	
Mountaineer		1		WV		Steam - Coal		1,320 			1980	
Clinch River		2		VA		Steam - Natural Gas		465 			1958	
Total MWs		 		 		 		6,629 			 	

																																	
I&M		 		 		 		 		 	
Plant Name		Units		State		Fuel Type		Net Maximum
Capacity (MWs)		Year Plant
or First Unit Commissioned	
Berrien Springs		12		MI		Hydro		6 			1908	
Buchanan		10		MI		Hydro		3 			1919	
Constantine		4		MI		Hydro		1 			1921	
Elkhart		3		IN		Hydro		3 			1913	
Mottville		4		MI		Hydro		2 			1923	
Twin Branch Hydro		8		IN		Hydro		5 			1904	
Deer Creek Solar Farm		NA		IN		Solar		3 			2016	
Olive Solar Farm		NA		IN		Solar		5 			2016	
Twin Branch Solar Farm		NA		IN		Solar		3 			2016	
Watervliet		NA		MI		Solar		5 			2016	
Rockport (Units 1 and 2, 50% of each) (a)		2		IN		Steam - Coal		1,310 			1984	
Cook		2		MI		Steam - Nuclear		2,288 			1975	
Total MWs		 		 		 		3,634 			 	

NA    Not applicable.
(a)Rockport Plant, Unit 2 is leased.

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The following table provides operating information related to the Cook Plant:

 	Cook Plant	
 	Unit 1		Unit 2	
Year Placed in Operation	1975		1978	
Year of Expiration of NRC License	2034		2037	
Nominal Net Electrical Rating in MWs	1,084		1,204	
Annual Capacity Utilization	 		 	
2020	87.2 %		94.2 %	
2019	77.3 	%		84.3 	%	
2018	97.9 	%		79.5 	%	

																																	
KPCo		 		 		 		 		 	
Plant Name		Units		State		Fuel Type		Net Maximum
Capacity (MWs)		Year Plant
or First Unit Commissioned	
Mitchell (a)		2		WV		Steam - Coal		780 			1971	
Big Sandy		1		KY		Steam - Natural Gas		280 			1963	
Total MWs		 		 		 		1,060 			 	

(a)KPCo owns a 50% interest in the Mitchell Plant units.  WPCo owns the remaining 50%. Figures presented reflect only the portion owned by KPCo.

																																	
PSO		 		 		 		 		 	
Plant Name		Units		State		Fuel Type		Net Maximum
Capacity (MWs)		Year Plant
or First Unit Commissioned	
Comanche		3		OK		Natural Gas		248 			1973	
Riverside, Units 3 and 4		2		OK		Natural Gas		160 			2008	
Southwestern, Units 4 and 5		2		OK		Natural Gas		170 			2008	
Weleetka		2		OK		Natural Gas		100 			1975	
Northeastern, Unit 1		1		OK		Natural Gas		470 			1961	
Northeastern, Unit 3		1		OK		Steam - Coal		469 			1979	
Northeastern, Unit 2		1		OK		Steam - Natural Gas		434 			1961	
Riverside, Units 1 and 2		2		OK		Steam - Natural Gas		901 			1974	
Southwestern, Units 1, 2 and 3		3		OK		Steam - Natural Gas		451 			1952	
Tulsa		2		OK		Steam - Natural Gas		325 			1956	
Total MWs		 		 		 		3,728 			 	

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SWEPCo		 		 		 		 		 	
Plant Name		Units		State		Fuel Type		Net Maximum
Capacity (MWs)		Year Plant
or First Unit Commissioned	
Mattison		4		AR		Natural Gas		315 			2007	
Stall		3		LA		Natural Gas		534 			2010	
Flint Creek (a)		1		AR		Steam - Coal		258 			1978	
Turk (a)		1		AR		Steam - Coal		477 			2012	
Welsh (b)		2		TX		Steam - Coal		1,053 			1977	
Dolet Hills (a)(c)		1		LA		Steam - Lignite		257 			1986	
Pirkey (a)(d)		1		TX		Steam - Lignite		580 			1985	
Arsenal Hill		1		LA		Steam - Natural Gas		110 			1960	
Knox Lee		1		TX		Steam - Natural Gas		344 			1950	
Lieberman		3		LA		Steam - Natural Gas		217 			1947	
Wilkes		3		TX		Steam - Natural Gas		889 			1964	
Total MWs		 		 		 		5,034 			 	

(a)Jointly-owned with nonaffiliated entities.  Figures presented reflect only the portion owned by SWEPCo. The Arkansas jurisdictional portion of SWEPCo’s interest in Turk Plant is not in rate base.
(b)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(c)In March 2020, management announced plans to retire the plant in 2021.
(d)In November 2020, management announced plans to retire the plant in 2023.

																																	
WPCo		 		 		 		 		 	
Plant Name		Units		State		Fuel Type		Net Maximum
Capacity (MWs)		Year Plant
or First Unit Commissioned	
Mitchell (a)		2		WV		Steam - Coal		780 			1971	

(a)WPCo owns 50% in the Mitchell Plant units. KPCo owns the remaining 50%. Figures presented reflect only the portion owned by WPCo.

Generation & Marketing Segment

																																	
AGR		 		 		 		 		 	
Plant Name		Units		State		Fuel Type		Net Maximum
Capacity (MWs)		Year Plant
or First Unit Commissioned	
Racine		2		OH		Hydro		48 			1982	
Cardinal		1		OH		Steam - Coal		595 			1967	
Total MWs		 		 		 		643 			 	

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Renewable Power							
									
Size of Energy Resource		AEP Energy Supply, LLC Division		Renewable
Energy Resource		Location		In-Service or
Under Construction	
1,307 MW		AEP Renewables		Wind		Eight states (a)		In-service	
128 MW		AEP Renewables		Wind		Kansas		Under Construction	
20 MW		AEP Renewables		Solar		California		In-service	
20 MW		AEP Renewables		Solar		Utah		In-service	
50 MW		AEP Renewables		Solar		Nevada		In-service	
152 MW		AEP OnSite Partners		Solar		Sixteen states (b)		In-service	
9 MW		AEP OnSite Partners		Solar		Two states (c)		Under Construction	

(a)    Colorado, Hawaii, Indiana, Kansas, Michigan, Minnesota, Pennsylvania, and Texas.
(b)    California, Colorado, Florida, Hawaii, Illinois, Iowa, Minnesota, Nebraska, New Hampshire, New Jersey, New Mexico, New York, Ohio, Rhode Island, Texas and Vermont.
(c)    Ohio and Wisconsin.

TRANSMISSION AND DISTRIBUTION FACILITIES

The following tables set forth the total overhead circuit miles of transmission and distribution lines of the AEP System and its operating companies.

Vertically Integrated Utilities Segment

		Total Overhead Circuit Miles of Transmission and Distribution Lines	
APCo		51,675 		
I&M		21,201 		
KGPCo		1,407 		
KPCo		11,152 		
PSO		18,196 		
SWEPCo		26,134 		
WPCo		1,733 		
Total Circuit Miles		131,498 		

Transmission and Distribution Utilities Segment

		Total Overhead Circuit Miles of Transmission and Distribution Lines	
OPCo		44,838 		
AEP Texas		46,079 		
Total Circuit Miles		90,917 		
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AEP Transmission Holdco Segment

The following table sets forth the total overhead circuit miles of transmission lines of certain wholly-owned and joint venture-owned entities:

		Total Overhead Circuit Miles of Transmission Lines	
ETT		1,808 		
IMTCo		696 		
OHTCo		863 		
OKTCo		928 		
WVTCo		250 		
Pioneer		43 		
Prairie Wind Transmission		216 		
Transource Missouri		167 		
Transource West Virginia		24 		
Total Circuit Miles		4,995 		

TITLE TO PROPERTY

The AEP System’s generating facilities are generally located on lands owned in fee simple.  The greater portion of the transmission and distribution lines of the AEP System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority.  The rights of AEP’s public utility subsidiaries in the realty on which their facilities are located are considered adequate for use in the conduct of their business.  Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties.  AEP’s public utility subsidiaries generally have the right of eminent domain which permits them, if necessary, to acquire, perfect or secure titles to or easements on privately held lands used or to be used in their utility operations.  Legislation in Ohio and Virginia has restricted the right of eminent domain previously granted for power generation purposes.

SYSTEM TRANSMISSION LINES AND FACILITY SITING

Laws in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Tennessee, Texas, Virginia and West Virginia require prior approval of sites of generating facilities and/or routes of high-voltage transmission lines.  AEP has experienced delays and additional costs in constructing facilities as a result of proceedings conducted pursuant to such statutes and in proceedings in which AEP’s operating companies have sought to acquire rights-of-way through condemnation.  These proceedings may result in additional delays and costs in future years.

CONSTRUCTION PROGRAM

With input from its state utility commissions, the AEP System continuously assesses the adequacy of its transmission, distribution, generation and other facilities to plan and provide for the reliable supply of electric power and energy to its customers.  In this assessment process, assumptions are continually being reviewed as new information becomes available and assessments and plans are modified, as appropriate.  AEP forecasts approximately $7.5 billion of construction expenditures for 2021. Estimated construction 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.  See the “Budgeted Capital Expenditures” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report for additional information.

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POTENTIAL UNINSURED LOSSES

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to AEP’s generation plants and costs of replacement power.  Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could reduce net income and impact the financial conditions of AEP and other AEP System companies.  For risks related to owning a nuclear generating unit, see the “Nuclear Contingencies” section of Note 6 - Commitments, Guarantees and Contingencies included in the 2020 Annual Report for additional information.

ITEM 3.   LEGAL PROCEEDINGS

For a discussion of material legal proceedings, see Note 6 - Commitments, Guarantees and Contingencies included in the 2020 Annual Report for additional information.

ITEM 4.   MINE SAFETY DISCLOSURE

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC, a wholly-owned lignite mining subsidiary of SWEPCo, is subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act.  Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended December 31, 2020.

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PART II

ITEM 5.   MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

AEP

In addition to the AEP Common Stock Information section below, the remaining information required by this item is incorporated herein by reference to the material under the “Dividend Policy and Restrictions” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2020 Annual Report.

During the quarter ended December 31, 2020, neither AEP nor its publicly-traded subsidiaries purchased equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act.

AEP Texas, APCo, I&M, OPCo, PSO and SWEPCo

The common stock of these companies is held solely by AEP.  For more information see the “Dividend Restrictions” section of Note 14 - Financing Activities included in the 2020 Annual Report.

AEPTCo

AEP owns the entire interest in AEPTCo through its wholly-owned subsidiary AEP Transmission Holdco.

AEP COMMON STOCK INFORMATION

AEP common stock is principally traded using the trading symbol “AEP” on the NASDAQ Stock Market.  As of December 31, 2020, AEP had 55,475 registered shareholders. The performance graph below compares the cumulative total return among AEP, the S&P 500 Index and the S&P Electric Utilities Index over a five year period. The performance graph assumes an initial investment of $100 on December 31, 2015 and that all dividends were reinvested.

Source: S&P Dow Jones Indices LLC. Data as of December 31, 2020. Past performance is no guarantee of future results. Chart provided for illustrative purposes.

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ITEM 6.   SELECTED FINANCIAL DATA

The selected financial data previously required by Item 301 of Regulation S-K has been omitted in reliance on SEC Release No. 33-10890, Management’s Discussion and Analysis, Selected Financial Data, and Supplementary Financial Information.

ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

AEP

The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2020 Annual Report. Year-to-year comparisons between 2019 and 2018 have been omitted from this Form 10-K but may be found in "Management's Discussion and Analysis of Financial Condition" in Part II, Item 7 of our Form 10-K for the fiscal year ended December 31, 2019, which specific discussion is incorporated herein by reference.

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(a).  Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2020 Annual Report.

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

The information required by this item is incorporated herein by reference to the material under the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2020 Annual Report.

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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2020 Annual Reports

American Electric Power Company, Inc. and Subsidiary Companies
AEP Texas Inc. and Subsidiaries
AEP Transmission Company, LLC and Subsidiaries
Appalachian Power Company and Subsidiaries
Indiana Michigan Power Company and Subsidiaries
Ohio Power Company and Subsidiaries
Public Service Company of Oklahoma
Southwestern Electric Power Company Consolidated

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

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF ANNUAL REPORTS

		Page
Number	
American Electric Power Company, Inc. and Subsidiary Companies:			
	
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		57	
	Report of Independent Registered Public Accounting Firm		121	
	Management’s Report on Internal Control Over Financial Reporting		124	
	Consolidated Financial Statements		125	
				
AEP Texas Inc. and Subsidiaries:			
	Management’s Narrative Discussion and Analysis of Results of Operations		132	
	Report of Independent Registered Public Accounting Firm		137	
	Management’s Report on Internal Control Over Financial Reporting		139	
	Consolidated Financial Statements		140	
				
AEP Transmission Company, LLC and Subsidiaries:			
	Management’s Narrative Discussion and Analysis of Results of Operations		147	
	Report of Independent Registered Public Accounting Firm		150	
	Management’s Report on Internal Control Over Financial Reporting		152	
	Consolidated Financial Statements		153	
				
Appalachian Power Company and Subsidiaries:			
	Management’s Narrative Discussion and Analysis of Results of Operations		159	
	Report of Independent Registered Public Accounting Firm		163	
	Management’s Report on Internal Control Over Financial Reporting		165	
	Consolidated Financial Statements		166	
				
Indiana Michigan Power Company and Subsidiaries:			
	Management’s Narrative Discussion and Analysis of Results of Operations		173	
	Report of Independent Registered Public Accounting Firm		177	
	Management’s Report on Internal Control Over Financial Reporting		179	
	Consolidated Financial Statements		180	
				
Ohio Power Company and Subsidiaries:			
	Management’s Narrative Discussion and Analysis of Results of Operations		187	
	Report of Independent Registered Public Accounting Firm		191	
	Management’s Report on Internal Control Over Financial Reporting		194	
	Consolidated Financial Statements		195	
				
Public Service Company of Oklahoma:			
	Management’s Narrative Discussion and Analysis of Results of Operations		202	
	Report of Independent Registered Public Accounting Firm		206	
	Management’s Report on Internal Control Over Financial Reporting		208	
	Financial Statements		209	
				
Southwestern Electric Power Company Consolidated:			
	Management’s Narrative Discussion and Analysis of Results of Operations		216	
	Report of Independent Registered Public Accounting Firm		220	
	Management’s Report on Internal Control Over Financial Reporting		222	
	Consolidated Financial Statements		223	
				
Index of Notes to Financial Statements of Registrants		229	

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

AEP is one of the largest investor-owned electric public utility holding companies in the United States.  AEP’s electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

AEP’s subsidiaries operate an extensive portfolio of assets including:

•Approximately 223,000 circuit miles of distribution lines that deliver electricity to 5.5 million customers.
•Approximately 40,000 circuit miles of transmission lines, including approximately 2,200 circuit miles of 765 kV lines, the backbone of the electric interconnection grid in the eastern United States.
•Approximately 22,000 MWs of regulated owned generating capacity and approximately 4,700 MWs of regulated PPA capacity in 2 RTOs as of December 31, 2020, one of the largest complements of generation in the United States.

COVID-19

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 reduced demand for energy, particularly from commercial and industrial customers in 2020. Although AEP cannot predict the severity or duration of the impact of the COVID-19 pandemic, AEP currently anticipates a 0.2% increase in weather-normalized retail sales volume in 2021 as compared to 2020. For the year ended December 31, 2020, AEP experienced a reduction in weather-normalized retail sales volume of 2.2% as compared to the same period in 2019 primarily driven by a 5.7% decrease in the industrial customer class and a 4.2% decrease in the commercial customer class offset by an increase in demand of 3.2% from the residential customer class. The reduction in weather-normalized retail sales volume of 2.2% did not result in a significant decrease in the corresponding retail margins for the year ended December 31, 2020 as the increase in higher margin residential sales volumes partially offset the decreases in the industrial and commercial sales volumes. Furthermore, the rate design for certain industrial customers includes demand provisions designed to cover the fixed portion of utility costs minimizing the impact of the fluctuations in usage on revenues. AEP’s load forecast is highly dependent on many factors including, but not limited to, the speed and strength of economic recovery and the extent and duration of the next wave of COVID-19 infection. If the severity of the economic disruption increases, AEP’s future results of operations, financial condition, and cash flows could be further adversely impacted. See Customer Demand for additional information.

During the first quarter of 2020, AEP’s electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Shortly thereafter, AEP’s state regulators also imposed temporary moratoria on customary disconnection practices. During the third and the fourth quarters of 2020, most state regulators began to lift restrictions on disconnects. As of December 31, 2020, AEP had resumed disconnections in its regulated jurisdictions with the exception of Virginia, Kentucky and Arkansas. Disconnections resumed in Kentucky during January 2021. AEP continues to work with regulators and stakeholders in Virginia and Arkansas and management currently anticipates resuming customary disconnection practices in the first half of 2021. However, this timing could change if there is new legislation or other regulatory directives issued in the future. 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 accounts receivable.
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Throughout 2020, the Registrants reviewed current collections experience with historical trends, specifically reviewing metrics such as cash collections, days sales outstanding, daily customer deposits and aging summaries. In addition, the Registrants reviewed historical loss information generally comprised of a rolling 12-month average, in conjunction with a qualitative assessment of elements that impact the collectability of receivables, such as changes in economic factors, regulatory matters, industry trends, customer credit factors, payment plan options and other programs available to customers. Based on this review, the Registrants’ accounts receivable aging was negatively impacted primarily due to the suspension of customer disconnects, but has continued to improve throughout the fourth quarter of 2020 as disconnect moratoriums have ended in most jurisdictions. Accounts receivable aging is also improving due to AEP proactively engaging with customers to collect payments or establish payment arrangements for outstanding balances. AEP has received, from the states of Virginia and West Virginia, $10 million and $20 million, respectively, to apply to residential customer balances that are past-due. In addition, customers in other states have access to various programs that assist customers who have accumulated larger than normal past-due balances. As of December 31, 2020, 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 affecting suspensions of disconnections and its impact on customer collections. Further deterioration in AEP’s ability to collect from its customers could significantly impact AEP’s future results of operations, financial conditions and cash flows.

In May 2020, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As of December 31, 2020, 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. The receivables that are ineligible under the receivables securitization agreement are financed with short-term debt at AEP Credit.

The Registrants have worked with their state commissions to achieve deferral authority for incremental expenses incurred due to COVID-19. All of AEP’s regulated jurisdictions have issued COVID-19 orders, granting deferral authority for incremental COVID-19 expenses, with the exception of Kentucky and Tennessee. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.

The effects of the continued COVID-19 pandemic and related government responses could also include extended disruptions to supply chains, reduced labor availability, reduced dispatch for certain generation assets and a prolonged reduction in economic activity. These effects could have a variety of adverse impacts to the Registrants, including their ability to operate their facilities. As of December 31, 2020, there were no material adverse impacts to the Registrants’ operations and supplier contracts due to COVID-19. AEP will continue to monitor developments affecting facility operations and will take additional actions necessary in order to mitigate adverse impacts to the Registrants’ future results of operations, financial condition and cash flows.

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 existed as of December 31, 2020.

Market volatility and reduction in collections coupled with longer collection periods due to the expansion of customer payment arrangements could reduce cash from operations and cause an adverse impact to liquidity. During 2020, AEP increased its liquidity position to mitigate the market risk and the collections risk due to COVID-19. During the first quarter of 2020, AEP entered into a $1 billion 364–day term loan to reduce reliance on commercial paper and help mitigate potential future liquidity risks. The $1 billion 364-day term loan was repaid in the fourth quarter of 2020. In addition, during 2020, AEP issued approximately $5.6 billion in long-term debt. As of December 31, 2020, AEP’s available liquidity was $2.5 billion. Management believes the Registrants have adequate liquidity under existing credit facilities. In the first quarter of 2020, AEP shifted capital expenditures of
58

$500 million out of 2020 into future periods to further mitigate adverse liquidity impacts. In the second quarter of 2020, AEP reinstated $100 million of capital expenditures back into 2020 that had previously been deferred. To the extent that future access to the capital markets or the cost of funding is adversely affected by COVID-19, future results of operations, financial condition, and cash flows may be adversely impacted.

In March 2020, the CARES Act was signed into law. The CARES Act includes tax relief provisions such as: (a) an AMT Credit Refund, (b) a 5-year NOL carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. Pursuant to the CARES Act, AEP, APCo and OPCo requested and in July received refunds of AMT credit of $20 million, $7 million and $9 million, respectively. In the third quarter of 2020, AEP also requested a $95 million refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. AEP carried back a NOL generated on the 2019 Federal income tax return at a 21% federal corporate income tax rate to the 2014 Federal income tax return at a 35% corporate income tax rate. As a result of the change in the corporate income tax rates between the two periods, AEP realized a tax benefit of $48 million primarily at the Generation & Marketing segment. Management will continue to monitor potential legislation and any impacts to the AMT Credit and NOL refunds that were filed in 2020 pursuant to the CARES Act. The Registrants deferred payments of the employer share of payroll taxes for the period March 27, 2020 through December 31, 2020 and will pay 50% of the obligation by December 31, 2021 and the remaining 50% by December 31, 2022. As of December 31, 2020, the Registrants have deferred $55 million of the employer share of payroll taxes.

In December 2020, the CAA of 2021 was signed into law. The CAA of 2021 includes: (a) COVID-19 tax relief and tax extender provisions including extensions of time to begin construction on and placed in-service assets generating PTCs and ITCs, (b) 100% deductibility of business meals in 2021 and 2022 and (c) an extension of the work opportunity tax credit. The ITC percentage has been increased for projects starting construction through 2023 and placed in-service by the end of 2025. The PTC has been extended for an additional year, to include projects started in 2021 and completed in 2025. These provisions provide time and flexibility on the construction start and in-service dates.

The Registrants have taken 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 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 extra precautions for employees who work in the field and for employees who work in their facilities, and have 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 December 31, 2020, 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.

Customer Demand

AEP’s weather-normalized retail sales volumes for the year ended December 31, 2020 decreased by 2.2% from the year ended December 31, 2019. Weather-normalized residential sales increased 3.2% for the year ended December 31, 2020 compared to the year ended December 31, 2019. AEP’s 2020 industrial sales volumes decreased 5.7% compared to 2019. The decline in industrial sales was spread across many industries. Weather-normalized commercial sales decreased by 4.2% in 2020 compared to 2019.

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In 2021, AEP anticipates weather-normalized retail sales volumes will increase by 0.2%. The industrial class is expected to increase by 1.9% in 2021, while weather-normalized residential sales volumes are projected to decrease by 1.1%. Finally, AEP projects weather-normalized commercial sales volumes to decrease by 0.5%.

(a)Percentage change for the year ended December 31, 2020 as compared to the year ended December 31, 2019.
(b)Forecasted percentage change for the year ended December 31, 2021 compared to the year ended December 31, 2020.

Regulatory Matters

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.

•2017-2019 Virginia Triennial Review - In March 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $65 million annual increase in base rates based upon a proposed 9.9% ROE. Triennial reviews are subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. In 2015, APCo retired the Sporn Plant, the Kanawha River Plant, the Glen Lyn Plant, Clinch River Unit 3 and the coal portions of Clinch River Units 1 and 2 (collectively, the retired coal-fired generation assets). The net book value of the Virginia jurisdictional share of these plants was $93 million before cost of removal, including materials and supplies inventory and ARO balances. Based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million related to its previously retired coal-fired generation assets in December 2019. As a result, management deemed these costs to be substantially recovered by APCo during the triennial review period. Inclusive of the Virginia jurisdictional share of the $93 million expense associated with APCo’s retired coal-fired generation assets, APCo calculated its 2017-2019 Virginia earnings for the triennial period to be below the authorized ROE range.

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In November 2020, the Virginia SCC issued an order 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 also disagreed with APCo’s treatment of the retired coal-fired generation assets for regulatory purposes, and instead adopted the Virginia SCC Staff’s recommendation to treat the remaining unrecovered costs of the retired coal-fired generation assets as a regulatory asset to be amortized over 10 years as of the June 2015 retirement date. The Virginia SCC’s adoption of the Staff’s recommended regulatory treatment of the coal-fired generation assets resulted in a net $40 million increase to APCo’s 2020 pretax income. In addition, the Virginia SCC’s order also included: (a) implementation of the Staff-modified APCo 2017 depreciation study effective January 1, 2018 and (b) implementation of the Staff-modified APCo 2019 depreciation study effective January 1, 2020. The adoption of these depreciation studies resulted in an approximate $47 million reduction to APCo’s 2020 pretax income comprised of a $44 million reduction to revenues for amounts recognized in advance of the recording of depreciation expense for the periods January 2018 through October 2020 and a $3 million increase in depreciation expense for the periods November and December 2020. A corresponding regulatory liability was recorded for the $44 million reduction to revenues. Also in November 2020, APCo filed a notice of appeal of the Virginia SCC’s order with the Virginia Supreme Court. In December 2020, an intervenor filed a petition at the Virginia SCC requesting reconsideration of: (a) the failure of the Virginia SCC to apply a threshold earnings test to the approved regulatory asset for APCo’s closed coal-fired generation assets, (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. Also 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 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. If the Virginia SCC did not conclude on APCo’s ability to earn a fair return, APCo requested the Virginia SCC provide such a conclusion. In January 2021, as requested by the Virginia SCC, APCo filed briefs related to the petition for reconsideration.

•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 November 2020, 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 staff’s proposal included a disallowance of plant in-service which could 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. A procedural schedule for the case is pending due to ongoing settlement discussions.

•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 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 December 31, 2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $84 million ($82 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $23 million, all of which is related to the Louisiana jurisdiction.

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•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. In August 2020, the Texas Supreme Court granted SWEPCo’s petition for review and oral arguments were held in December 2020. SWEPCo expects a decision from the Texas Supreme Court in 2021. As of December 31, 2020, 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 share of the Turk Plant investment is approximately 33%.

•In July 2019, clean energy legislation (HB 6) which offers incentives for power-generating facilities with zero or reduced carbon emissions was signed into law by the Ohio Governor.  HB 6 phased out current energy efficiency programs as of December 31, 2020, including shared savings revenues of $26 million annually and renewable mandates after 2026. HB 6 also provided for the recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for recovery of OVEC costs through 2030 which will be allocated to all electric distribution utilities on a non-bypassable basis.  OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a 501(c)(4) social welfare organization, in connection with a racketeering conspiracy involving the adoption of HB 6. In light of the allegations in the indictment, proposed legislation has been introduced that would repeal HB 6. The outcome of the U.S. Attorney’s Office investigation and its impact on HB 6 is not known. If the provisions of HB 6 were to be eliminated, it is unclear whether and in what form the Ohio General Assembly would pass new legislation addressing similar issues. 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 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. See Litigation Related to Ohio House Bill 6 section of Litigation below for additional information. 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, fully recover energy efficiency costs incurred through 2020 or incurs significant costs defending against 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 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
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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. 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.

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. 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		Michigan		$	36.4 		(a)		9.86%		February 2020	
I&M		Indiana		60.0 		(b)		9.7%		March 2020	
AEP Texas		Texas		(40.0)				9.4%		June 2020	
APCo		Virginia		— 		(c)		9.2%		February 2021	
KPCo		Kentucky		52.7 				9.3%		January 2021	

(a)See “2019 Michigan Base Rate Case” section of Note 4 Rate Matters in the 2019 Annual Report for additional information.
(b)Phased-in through an increase in base rates which included: (a) an annual increase in base rates of $44 million effective March 2020 and (b) an annual increase in base rates of $60 million effective January 2021 based on the IURC-approved forecast of December 31, 2020 Indiana jurisdictional electric plant in-service. The order rejected I&M’s proposed re-allocation of capacity costs related to the loss of a significant FERC wholesale contract, which negatively impacted I&M’s annual pretax earnings by approximately $20 million starting June 2020.
(c)APCo filed a notice of appeal with the Virginia Supreme Court and a petition requesting reconsideration with the Virginia SCC. In addition, an intervenor has also filed a petition requesting reconsideration with the Virginia SCC.

Pending Base Rate Case Proceedings

											Commission Staff/	
				Filing		Requested Revenue			Requested		Intervenor Range of	
Company		Jurisdiction		Date		Requirement Increase			ROE		Recommended ROE	
						(in millions)						
OPCo		Ohio		June 2020		$	42.3 				10.15%		8.76% - 9.78%	
SWEPCo		Texas		October 2020		105.0 		(a)		10.35%		(b)	
SWEPCo		Louisiana		December 2020		134.0 				10.35%		(c)	

(a)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.
(b)Intervenor and staff testimony is scheduled to be filed in March and April 2021, respectively.
(c)Awaiting procedural schedule.
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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. After careful consideration of current economic conditions, and particularly for the benefit of their customers, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. Based on these actions, management revised the estimated useful life of DHLC’s and Oxbow’s assets 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 cease in September 2021. Management also revised the useful life of the Dolet Hills Power Station to 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 cessation of lignite 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 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 fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $131 million as of December 31, 2020. Also, as of December 31, 2020, SWEPCo had a net over-recovered fuel balance of $35 million, which includes fuel burned 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 October 2020, SWEPCo filed a request with the LPSC for recovery of the Louisiana share of these additional fuel costs. SWEPCo’s filing proposes to defer $36 million of fuel costs in 2021 and recover the deferral plus carrying costs over five years beginning in 2022.

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

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 $212 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 $193 million as of December 31, 2020. Also, as of December 31, 2020, SWEPCo had a net over-recovered fuel balance of $35 million, which includes fuel burned 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.

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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 acquired an additional 10% interest, or approximately 30 MWs, in Santa Rita East. The project is located in west Texas and was placed in-service in July 2019. Long-term virtual power purchase agreements are in place with nonaffiliates for the project’s generation. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.

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. Management expects the transaction to close in the first quarter of 2021 and the solar project is expected to be in-service in the second quarter of 2021.

As of December 31, 2020, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,549 MWs of contracted renewable generation projects in-service.  In addition, as of December 31, 2020, these subsidiaries had approximately 137 MWs of renewable generation projects under construction with total estimated capital costs of $208 million related to these projects.

Regulated Renewable Generation Facilities

In 2020, PSO received approval from the OCC and SWEPCo received approval from the 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. Both the APSC and LPSC approved the flex-up option, agreeing to 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.

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, will qualify for 80% of the federal PTC.

Having regulatory approval, and the expectation that all three wind facilities will be eligible for the IRS extension of the “Continuity Safe Harbor,” PSO and SWEPCo are proceeding with the full 1,485 MW development of these three projects. The 199 MW wind facility is targeted to be acquired and placed in-service in March 2021. The 287 MW wind facility is targeted to be acquired and placed in-service in December 2021 and the 999 MW wind facility is targeted to be acquired and placed in-service between December 2021 and April 2022.

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Hydroelectric Generation

Evaluating Sale of Hydroelectric Generation

In March 2020, management placed 10 hydroelectric generation plants under study for a potential sale. In April 2020, the Virginia Clean Economy Act was signed into law by the Virginia Governor. The new law will provide renewable credits to APCo for its existing hydroelectric generation plants. As a result of the new law, management removed the three APCo hydroelectric generation plants (London, Marmet and Winfield) from the list of plants identified for potential sale. In December 2020, management decided they would only proceed with the potential sale of Racine. The two Racine units have a net maximum capacity of 48 MWs and the net book value is $45 million as of December 31, 2020. In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated party. The sale of Racine requires FERC approval. The sale is expected to close in the second quarter of 2021 and result in an immaterial gain. Racine was not presented as Held for Sale on AEP’s Consolidated Balance Sheets due to immateriality.

Federal Tax Reform

Based on current regulatory orders received, management anticipates amortization of $233 million of Excess ADIT in 2021 ($64 million of Excess ADIT subject to normalization requirements and $169 million of Excess ADIT that is not subject to normalization requirements). Customer usage or new regulatory orders could result in changes to these estimates. Management anticipates amortizing the following ranges of Excess ADIT that is not subject to normalization requirements during the years 2022 through 2026:

Annual Amortization of Excess ADIT
Not Subject to Normalization Requirements

Year		Range	
		(in millions)		
2022		$	75.0 			-	$	105.0 			
2023		68.0 			-	98.0 			
2024		35.0 			-	65.0 			
2025		5.0 			-	26.0 			
2026		5.0 			-	25.0 			

Merchant Portion of Turk Plant

SWEPCo constructed the Turk Plant, a base load 600 MW (650 MW net maximum capacity) pulverized coal ultra-supercritical generating unit in Arkansas, which was placed in-service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MWs/477 MWs) of the Turk Plant and operates the facility.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This share of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under cost-based rate recovery in Texas, Louisiana and through SWEPCo’s wholesale customers under FERC-based rates. As of December 31, 2020, the net book value of Turk Plant was $1.4 billion, before cost of removal, including materials and supplies inventory and CWIP. If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

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FERC Transmission ROE Methodology

Management continues to monitor FERC’s 2019 Notice of Inquiry regarding base ROE policy, FERC’s 2020 Notice of Proposed Rulemaking regarding transmission incentives policy, and various other matters pending before FERC with the potential to affect FERC transmission ROE methodology.

In the second quarter of 2019, 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 the second quarter of 2020, FERC Order 569A determined the base ROE for MISO’s transmission owning members, including AEP’s MISO transmission-owning subsidiaries, should be 10.02% (10.52% inclusive of the RTO incentive adder of 0.5%).

If FERC makes any changes to its ROE and incentive policies, they 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.

Impacts of Severe Winter Weather in February 2021

In February 2021, many of AEP’s service territories and customers were impacted by severe winter weather and extreme cold temperatures resulting in power outages, extensive damage to transmission and distribution infrastructure and disruption to the energy markets.

Storm Costs

Based on the information currently available, APCo, KPCo and SWEPCo currently estimate significant February 2021 storm restoration expenditures as shown in the table below. Management currently anticipates the storm restoration expenditures will be more heavily weighted towards other operation and maintenance expenses as compared to capital expenditures. Management will continue to refine these storm cost estimates as restoration efforts are completed and final costs become available.

		Total Estimated February 2021
Storm Restoration Expenditures	
		(in millions)	
APCo		$65.0	-	$75.0	
KPCo		$75.0	-	$95.0	
SWEPCo		$30.0	-	$40.0	

Management plans to seek regulatory recovery of these costs. If any of the storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
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February 2021 Severe Winter Weather Impacts in SPP

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, based on the information currently available, PSO’s and SWEPCo’s preliminary estimates of natural gas expenses and purchases of electricity are as follows:

		PSO		SWEPCo	
		(in millions)	
Estimated Natural Gas Expenses		$	175.0 			$	375.0 		
Estimated Electricity Purchases		650.0 			— 		
		$	825.0 			$	375.0 		

The amounts in the table above represent preliminary estimates as of February 25, 2021, and are subject to final settlement as additional information becomes available. In addition, SPP notified PSO and SWEPCo of additional collateral requirements of approximately $868 million on a cumulative basis for the companies due March 2, 2021. Subsequently, SPP filed a waiver request with the FERC that would grant a limited waiver for Load Serving Entities to post this additional collateral requirement between February 24, 2021 and March 11, 2021. FERC approved the waiver request on February 24, 2021.

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 regulators to perform a heightened review of the costs. Management believes these costs are probable of future recovery. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. Nevertheless, PSO and SWEPCo’s payments to suppliers are due in March 2021.

PSO and SWEPCo are evaluating financing alternatives including funding contributions from Parent and long-term debt issuances to address the timing difference between the payment to suppliers and recovery from customers. If either PSO or SWEPCo is unable to recover these fuel and purchased power expenses or recover these expenses in a timely manner, it could reduce future net income and cash flows and impact financial condition.

ERCOT

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. While recovery from the emergency conditions is continuing, some market conditions and activities have yet to return to normal. 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.
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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 6 – 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.

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.

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.

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. The district court’s stay of the lease litigation expired in August 2020. Upon expiration of the stay, plaintiffs filed a motion for partial summary judgment, 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 judgement was filed in October 2020. At the parties’ request, the district court stayed the case until February 16, 2021 to provide the parties an opportunity to resolve the case, and the court has since extended the stay until April 26, 2021. See “Modification of the New Source Review Litigation Consent Decree” section below for additional information.

Management will continue to defend against the claims and believes its financial statements appropriately reflect the potential outcome of the pending litigation. The ultimate outcome of the pending litigation could reduce future net income and cash flows and impact financial condition.

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Patent Infringement Complaint

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 alleges that the AEP Defendants infringed two patents owned by the plaintiffs by using specific processes for mercury control at certain coal-fired generating stations. The complaint was resolved in December 2020 and did not have a material impact on net income, cash flows or financial condition.

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: (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, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act 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. The denial of those claims was appealed to the AEP System Retirement Plan Appeal 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 is reasonably possible of occurring.

Litigation Related to Ohio House Bill 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 complaint alleges misrepresentations or omissions by AEP regarding: (a) its alleged participation in public corruption with respect to the passage of Ohio House Bill 6, (b) its regulatory, legislative and lobbying activities in Ohio and (c) its clean energy strategy. 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. The 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 complaints assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets and (c) unjust enrichment 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.

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 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,
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along with other parties, challenged some 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 December 31, 2020, the AEP System owned generating capacity of approximately 24,400 MWs, of which approximately 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 $350 million to $700 million through 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.

Modification of 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 NOX emissions from the AEP System and various mitigation projects.

In 2017, AEP filed a motion with the district court seeking to modify 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. Construction of the SCR technology was completed by June 1, 2020, testing was conducted, and the unit was released for dispatch on June 5, 2020.

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 NOX at the combined stack for the Rockport Plant beginning in 2021. Total SO2 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.
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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 reviewed the existing standards for NO2 and SO2 in 2018 and 2019, respectively, and decided to retain the standards without change. Implementation of these standards is underway. The Federal EPA recently reviewed the existing standards for PM and ozone and in December 2020 announced both standards would be retained without change.

The Federal EPA finalized non-attainment designations for the 2015 ozone standard in 2018. The Federal EPA confirmed that for states included in the CSAPR program, there are no additional interstate transport obligations, as all areas of the country are expected to attain the 2008 ozone standard before 2023. Challenges to the 2015 ozone standard and the Federal EPA’s determination that CSAPR satisfies certain states’ interstate transport obligations 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 eliminated by the attainment deadlines for downwind states. Any further changes will require additional rulemaking. Management cannot currently predict the nature, stringency or timing of additional requirements for AEP’s facilities based on the outcome of these activities.

Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) would address regional haze in federal parks and other protected areas.  BART requirements apply to certain power plants.  CAVR will be implemented through SIPs or 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 regional haze SIP, but has approved a revised SIP and all of SWEPCo's affected units are in compliance with the relevant requirements.

The Federal EPA also disapproved portions of the Texas regional haze SIP. In 2017, the Federal EPA finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOX regional 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 to the FIP was filed in the U.S. Court of Appeals for the Fifth Circuit and the case is pending the Federal EPA’s reconsideration of 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. The Federal EPA finalized the intrastate trading program in July 2020, and that rule has been challenged in the U.S. Court of Appeals for the Fifth Circuit as well as in the U.S. Court of Appeals for the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and has intervened in the litigation in support of the Federal EPA.
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Cross-State Air Pollution Rule

In 2011, the Federal EPA issued CSAPR as a replacement for the Clean Air Interstate Rule, 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 NOX 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 the Federal EPA over-controlled the SO2 and/or NOX budgets 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.

In October 2020, the Federal EPA proposed a revised CSAPR Update rule, which would substantially reduce the ozone season NOX budgets in 2021-2024. The Federal EPA recently released the underlying modeling and budget allocations and management is evaluating the potential impacts of this proposed rule.

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.

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. The rule has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit.

Climate Change, CO2 Regulation and Energy Policy

In 2015, the Federal EPA published the final CO2 emissions standards for new, modified and reconstructed fossil generating units, and final guidelines for the development of state plans to regulate CO2 emissions from existing sources, known as the Clean Power Plan (CPP). Implementation of the CPP was stayed by the U.S. Supreme Court pending the outcome of legal challenges, and the CPP was ultimately repealed by the Federal EPA in 2019 and
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replaced with the Affordable Clean Energy (ACE) rule. ACE established a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. States were to submit their plans for implementing the ACE rule in 2022, and the Federal EPA would have had up to two years to review and approve a plan or disapprove it and adopt a federal plan. However, in January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE rule and remanded it to the Federal EPA. It is too soon to predict how the Federal EPA will respond to the 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 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 an 80% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is net-zero CO2 emissions from AEP generating facilities by 2050. AEP’s total estimated CO2 emissions in 2020 were approximately 44 million metric tons, a 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. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers.

Excessive costs to comply with future legislation or regulations has led to the announcement of early plant closures and could force AEP to close additional coal-fired generation facilities earlier than their estimate useful life. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.

Coal Combustion Residual (CCR) Rule

In 2015, the Federal EPA published a final rule to regulate 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 two 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, are the subject of further rulemaking that has not been finalized.
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Prior to the court’s decision, the Federal EPA issued the July 2018 rule that modifies certain compliance deadlines and other requirements in the 2015 rule.  In December 2018, challengers filed a motion for partial stay or vacatur of the July 2018 rule. On the same day, the Federal EPA filed a motion for partial remand of the July 2018 rule. The court granted the Federal EPA’s motion. In November 2019, the Federal EPA proposed revisions to implement the court’s decision regarding the timing for closure of unlined surface impoundments along with impoundments not meeting the required distance from an aquifer. The final rule was published in August 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.

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 water 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. In December 2020, the Federal EPA issued draft guidance for public comment on applying the outcome of the Supreme Court’s decision and consideration of functionally equivalent factors. Management is unable to predict the impact of these developments on AEP’s facilities.

In August 2020, the Federal EPA revised the CCR rule to include a requirement that unlined CCR storage ponds cease operations and 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		$	2,171.8 			2040	
APCo		Mountaineer		1,320		980.2 			2040	
SWEPCo		Flint Creek Plant		258		279.2 			2038	
KPCo		Mitchell Plant		780		605.1 			2040	
WPCo		Mitchell Plant		780		603.7 			2040	
AEGCo		Rockport Plant, Unit 1		655		248.9 			2028	
I&M		Rockport Plant, Unit 1		655		573.8 		(b)	2028	

(a)Net book value before cost of removal including CWIP and inventory.
(b)Amount includes a $191 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 2015 and 2014, respectively.
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In December 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 $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 facilities with CCR storage ponds greater than 40 acres in size. Pursuant to this option, AEP informed the Federal EPA of its intent to retire the Pirkey Power Plant and cease using coal at the 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		$	199.5 			$	12.2 			2023 (b)	
SWEPCo		Welsh Plants, Units 1 & 3		1,053		549.8 			3.6 			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 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(d)Unit 1 is currently being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is currently being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

AEP may incur significant costs to upgrade or close and replace 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), effective July 2020, requiring APCo to close certain ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material.  As a result, in June 2020, APCo recorded a $199 million revision to increase estimated Glen Lyn Station ash disposal ARO liabilities.  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 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. APCo will submit filings with the Virginia SCC and the WVPSC requesting recovery of the respective Virginia and West Virginia jurisdictional shares of these Glen Lyn Station ARO costs. As of December 31, 2020, APCo has not yet incurred any incremental costs associated with the removal of coal combustion material at the Glen Lyn Station.

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 been closed in place in
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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 Federal EPA issued a final 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. AEP facilities that have had their wastewater discharge permits renewed have been asked to monitor intake flows or to enhance monitoring practices to assure the current technology is being properly managed to ensure compliance with this rule.

In 2015, the Federal EPA issued a final rule revising effluent limitation guidelines for generating facilities. The rule established limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater 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 rule was challenged in the U.S. Court 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 the compliance deadlines for those wastewater categories to be no earlier 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. A final rule was signed by the Federal EPA in August 2020 and was published in October 2020. The final rule establishes additional options for reusing and discharging small volumes of bottom ash transport water, provides an exception for retiring units, and extends the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025. Management 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 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.

In 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of 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 2015 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 in the Federal Register in April 2020 and became effective in June 2020. The final rule limits the scope of CWA jurisdiction to four categories of waters, and clarifies exclusions for ground water, ephemeral streams, artificial ponds and waste treatment systems. Challenges to the final rule and requests for a preliminary injunction have been brought by states and other groups in multiple U.S. District Courts. At this time, none of the jurisdictions in which AEP operates are impacted by a stay. Management is monitoring these various proceedings but is unable to predict the actions of the various courts.

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 (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. In May 2020, the Court revised its order lifting the injunction for non-oil and gas pipeline construction activities and routine maintenance, inspection and repair activities on existing NWP 12 projects. The Department of Justice appealed the Court’s decision to the Court of Appeals for the Ninth Circuit
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and moved for stay pending appeal, which was denied. In June 2020, the Department of Justice submitted an application to the U.S. Supreme Court requesting a stay of the District Court’s Order, and the Court granted the request with respect to all oil and gas pipelines except the Keystone Pipeline. Management is monitoring the litigation, but is currently unable to predict the impact of future proceedings on current and planned projects.

In September 2020, the Corps issued for public comment the proposed renewal of all General Nationwide Permits. As part of that proposal the Corps narrowed the focus of NWP 12 to only oil and natural gas pipeline activities. The Corps proposed two new Nationwide Permits governing electric utility line and telecommunications activities, and other utility lines (e.g., conveyance of potable water, sewage, other substances), respectively. In January 2021, the Corps issued 16 final Nationwide Permits, including NWP 12 and the two new utility line permits, NWP 57 and NWP 58. The Corps chose not to reissue or modify the remaining Nationwide Permits at this time. The 2017 versions of those permits remain in effect. Management is currently assessing impacts of the rulemaking on current and planned projects.

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 addition to the November 2020 announcement related to the Federal 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 net book value, as of December 31, 2020, 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		$	74.4 			$	71.2 			2021		(c)		$	60.8 		
PSO		Northeastern Plant, Unit 3		198.4 			110.4 			2026		(d)		14.9 		
PSO		Oklaunion Power Station		— 			34.4 			2020		(e)		— 		
SWEPCo		Pirkey Power Plant		199.5 			12.2 			2023		(f)		13.8 		
SWEPCo		Welsh Plant, Units 1 and 3		549.8 			3.6 			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 amount of annual depreciation that has been collected from customers over the prior 12-month period.
(c)Dolet Hills Power Station is current being recovered through 2026 in the Louisiana jurisdiction and through 2046 in 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 through 2037 in the 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 Welsh Plant, Units 1 and 3.

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, cash flows and impact financial condition.
78

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 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.
•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.

Generation & Marketing

•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 2020 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’ 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.

79

A detailed discussion of AEP’s 2019 results of operations by operating segment can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operation section included in the 2019 Annual Report on Form 10-K filed with the SEC on February 20, 2020.

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

		Years Ended December 31,	
		2020		2019		2018	
		(in millions)	
Vertically Integrated Utilities		$	1,061.6 			$	982.0 			$	990.5 		
Transmission and Distribution Utilities		496.4 			451.0 			527.4 		
AEP Transmission Holdco		504.8 			516.3 			369.9 		
Generation & Marketing		226.9 			112.8 			135.3 		
Corporate and Other		(89.6)			(141.0)			(99.3)		
Earnings Attributable to AEP Common Shareholders		$	2,200.1 			$	1,921.1 			$	1,923.8 		

Note: 2020 Earnings Attributable to AEP Common Shareholders by Segment excludes Corporate and Other which is not considered a reportable segment.

AEP CONSOLIDATED

2020 Compared to 2019

Earnings Attributable to AEP Common Shareholders increased from $1.9 billion in 2019 to $2.2 billion in 2020 primarily due to:

•Favorable rate proceedings in AEP’s various jurisdictions.
•A planned decrease in Other Operation and Maintenance expenses.
•Continued transmission investment, which resulted in higher revenues and income.

These increases were partially offset by:

•A decrease in weather-related usage.
•A one-time reversal of a regulatory provision in 2019.

AEP’s results of operations by reportable segment are discussed below.
80

VERTICALLY INTEGRATED UTILITIES

(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

																					
		Years Ended December 31,	
Vertically Integrated Utilities		2020		2019		2018	
		(in millions)	
Revenues		$	8,879.4 			$	9,367.1 			$	9,645.5 		
Fuel and Purchased Electricity		2,544.9 			3,103.1 			3,488.9 		
Gross Margin		6,334.5 			6,264.0 			6,156.6 		
Other Operation and Maintenance		2,754.3 			2,934.4 			2,959.8 		
Asset Impairments and Other Related Charges		— 			92.9 			3.4 		
Depreciation and Amortization		1,600.5 			1,447.0 			1,316.2 		
Taxes Other Than Income Taxes		472.6 			460.9 			433.2 		
Operating Income		1,507.1 			1,328.8 			1,444.0 		

Other Income		2.4 			6.1 			17.0 		
Allowance for Equity Funds Used During Construction		42.2 			50.7 			35.4 		
Non-Service Cost Components of Net Periodic Benefit Cost		67.9 			67.6 			69.9 		
Interest Expense		(565.0)			(568.3)			(567.8)		
Income Before Income Tax Expense (Benefit) and
Equity Earnings		1,054.6 			884.9 			998.5 		
Income Tax Expense (Benefit)		(7.0)			(97.7)			5.7 		
Equity Earnings of Unconsolidated Subsidiary		2.9 			3.0 			2.7 		
Net Income		1,064.5 			985.6 			995.5 		
Net Income Attributable to Noncontrolling Interests		2.9 			3.6 			5.0 		
Earnings Attributable to AEP Common Shareholders		$	1,061.6 			$	982.0 			$	990.5 		
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Summary of KWh Energy Sales for Vertically Integrated Utilities		
								
		Years Ended December 31,		
		2020		2019		2018		
		(in millions of KWhs)		
Retail:								
Residential		31,526 			32,359 			33,908 			
Commercial		22,225 			23,839 			24,452 			
Industrial		32,860 			35,252 			35,730 			
Miscellaneous		2,185 			2,302 			2,330 			
Total Retail		88,796 			93,752 			96,420 			
								
Wholesale (a)		16,987 			20,090 			22,682 			
								
Total KWhs		105,783 			113,842 			119,102 			

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

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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	
							
		Years Ended December 31,	
		2020		2019		2018	
		(in degree days)	
Eastern Region							
Actual – Heating (a)		2,295 			2,617 			2,886 		
Normal – Heating (b)		2,727 			2,732 			2,738 		
							
Actual – Cooling (c)		1,222 			1,369 			1,443 		
Normal – Cooling (b)		1,104 			1,092 			1,083 		
							
Western Region							
Actual – Heating (a)		1,160 			1,512 			1,599 		
Normal – Heating (b)		1,464 			1,473 			1,475 		
							
Actual – Cooling (c)		2,117 			2,328 			2,502 		
Normal – Cooling (b)		2,253 			2,240 			2,230 		

(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.

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2020 Compared to 2019

Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)

Year Ended December 31, 2019		$	982.0 		
			
Changes in Gross Margin:			
Retail Margins		30.7 		
Margins from Off-system Sales		(12.5)		
Transmission Revenues		60.3 		
Other Revenues		(8.0)		
Total Change in Gross Margin		70.5 		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		180.1 		
Asset Impairments and Other Related Charges		92.9 		
Depreciation and Amortization		(153.5)		
Taxes Other Than Income Taxes		(11.7)		

Other Income		(3.7)		
Allowance for Equity Funds Used During Construction		(8.5)		
Non-Service Cost Components of Net Periodic Pension Cost		0.3 		
Interest Expense		3.3 		
Total Change in Expenses and Other		99.2 		
			
Income Tax Expense		(90.7)		
Equity Earnings of Unconsolidated Subsidiary		(0.1)		
Net Income Attributable to Noncontrolling Interests		0.7 		
			
Year Ended December 31, 2020		$	1,061.6 		

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 $31 million primarily due to the following:
•A $35 million increase in deferred fuel at APCo and WPCo primarily due to the timing of recoverable PJM expenses.
•A $20 million increase at APCo and WPCo due to the WVPSC approval of the Mitchell Plant surcharge effective January 1, 2020. Pursuant to the WVPSC approval of the surcharge, this increase was partially offset by the amortization of Excess ADIT not subject to normalization requirements in Income Tax Expense below.
•A $17 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
•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.
•A $10 million increase at APCo and WPCo due to revenue from rate riders primarily in West Virginia. This increase was partially offset in other expense items below.
•A $9 million increase due to an environmental expense deferral at APCo.
•An $8 million increase in weather-normalized retail margins driven by a $111 million increase in the residential customer class partially offset by a $97 million decrease in the commercial and industrial classes.

84

•The effect of rate proceedings in AEP’s service territories which included:
•A $109 million increase at I&M primarily due to the Indiana and Michigan base rate cases and increases in rider revenues. This increase was partially offset in other expense items below.
•A $45 million increase at SWEPCo primarily due to rider increases in all jurisdictions and a base rate revenue increase in Arkansas. This increase was partially offset in other expense items below.
•A $10 million increase at PSO due to new base rates implemented in April 2019.
•An $8 million increase at APCo and WPCo due to new base rates implemented in 2019 in West Virginia. This increase was partially offset in Depreciation and Amortization expenses below.
These increases were partially offset by:
•A $128 million decrease in weather-related usage primarily in the eastern region and primarily in the residential class.
•A $66 million decrease in weather-normalized margins for wholesale contracts, including the loss of a significant wholesale contract at I&M.
•A $44 million decrease due to the cumulative impact of the implementation of APCo’s 2017 and 2019 generation and distribution depreciation studies as ordered in the Virginia triennial base rate case.
•A $13 million decrease in revenue from rate riders at PSO. This decrease was partially offset in other expense items below.
•Margins from Off-system Sales decreased $13 million due to weaker market prices for energy in the RTOs which caused a decrease in sales margins and volume. In addition, the historical merchant portion of WPCo’s Mitchell Plant moved to retail rates beginning in January 2020.
•Transmission Revenues increased $60 million primarily due to the following:
•A $31 million increase as a result of the annual transmission formula rate true-up primarily at SWEPCo. This increase was partially offset by an increase in transmission expenses in SPP.
•A $22 million increase due to continued investment in transmission projects primarily at SWEPCo.
•A $12 million increase at APCo resulting from the 2017-2019 Virginia triennial base rate case. This increase was offset in Depreciation Expense below.
•Other Revenues decreased $8 million primarily due to the following:
•A $10 million decrease at I&M primarily due to a decrease in barging revenues by River Transportation Division. This decrease was partially offset in Other Operation and Maintenance expenses below.
•An $8 million decrease primarily due to suspension of late fees and disconnections in 2020 as a result of the COVID-19 pandemic.
These decreases were partially offset by:
•A $9 million increase at PSO primarily due to business development revenue. This increase was partially offset in other expense items below.

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

•Other Operation and Maintenance expenses decreased $180 million primarily due to the following:
•A $49 million decrease due to the re-establishment of a regulatory asset in 2020 as result of APCo’s 2017-2019 Virginia triennial review which authorized the recovery of previously retired coal-fired generation assets.
•A $47 million decrease in plant outage and maintenance expenses primarily at APCo, I&M, WPCo, KPCo and PSO.
•A $34 million decrease in charitable contributions primarily driven by the contribution to the AEP Foundation in 2019.
•A $32 million decrease in distribution expenses primarily related to vegetation management and other distribution expenses.
•A $28 million decrease in transmission expenses primarily related to accelerated vegetation management and maintenance in 2019.
•A $15 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs at SWEPCo and PSO.
•A $14 million decrease related to a 2020 insurance settlement primarily at SWEPCo and PSO.
•An $8 million decrease due to the modification of the NSR consent decree impacting I&M and AEGCo in 2019.
85

•A $7 million decrease at I&M due to an increased Nuclear Electric Insurance Limited distribution in 2020.
These decreases were partially offset by:
•A $39 million increase due to SPP transmission services including the annual formula rate true-up.
•A $37 million increase in employee-related expenses.
•Asset Impairments and Other Related Charges decreased $93 million primarily due to a pretax expense recorded in 2019 related to previously retired coal-fired assets.
•Depreciation and Amortization expenses increased $154 million primarily due to a higher depreciable base and increased depreciation rates approved at I&M, APCo and SWEPCo. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $12 million primarily due to increased property taxes primarily at APCo, I&M, PSO and SWEPCo.
•Other Income decreased $4 million primarily due to a decrease in affiliated interest income due to a decrease in interest rates in 2020.
•Allowance for Equity Funds Used During Construction decreased $9 million primarily due to a decrease in the AFUDC base at I&M and the favorable impact of a FERC settlement agreement recorded in 2019.
•Interest Expense decreased $3 million primarily due to the following:
•A $10 million decrease primarily due to lower interest rates on long-term debt primarily at PSO and AEGCo.
•A $6 million decrease primarily due to lower interest rates on variable rate loans and carrying charges recorded on various riders at I&M. This decrease was partially offset by a decrease in AFUDC base.
These decreases were partially offset by:
•A $13 million increase primarily due to higher long-term debt balances at APCo.
•Income Tax Expense increased $91 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 not subject to normalization requirements is partially offset above in Gross Margin and Other Operation and Maintenance expenses.
86

TRANSMISSION AND DISTRIBUTION UTILITIES

(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

		Years Ended December 31,	
Transmission and Distribution Utilities		2020		2019		2018	
		(in millions)	
Revenues		$	4,345.9 			$	4,482.5 			$	4,653.1 		
Purchased Electricity		682.7 			794.3 			858.3 		
	
Amortization of Generation Deferrals		— 			65.3 			223.9 		
Gross Margin		3,663.2 			3,622.9 			3,570.9 		
Other Operation and Maintenance		1,575.4 			1,628.1 			1,541.7 		
Asset Impairments and Other Related Charges		— 			32.5 			— 		
Depreciation and Amortization		751.1 			789.5 			734.1 		
Taxes Other Than Income Taxes		586.7 			575.0 			545.3 		
Operating Income		750.0 			597.8 			749.8 		
Interest and Investment Income		2.4 			6.6 			4.2 		
Carrying Costs Income		1.6 			1.0 			1.7 		
	
Allowance for Equity Funds Used During Construction		31.9 			33.4 			29.9 		
Non-Service Cost Components of Net Periodic Benefit Cost		29.4 			30.3 			32.3 		
Interest Expense		(289.2)			(243.3)			(248.1)		
Income Before Income Tax Expense (Benefit)		526.1 			425.8 			569.8 		
Income Tax Expense (Benefit)		29.7 			(25.2)			42.4 		
Net Income		496.4 			451.0 			527.4 		
Net Income Attributable to Noncontrolling Interests		— 			— 			— 		
Earnings Attributable to AEP Common Shareholders		$	496.4 			$	451.0 			$	527.4 		
87

																								
Summary of KWh Energy Sales for Transmission and Distribution Utilities		
								
		Years Ended December 31,		
		2020		2019		2018		
		(in millions of KWhs)		
Retail:								
Residential		26,518 			26,407 			27,042 			
Commercial		23,998 			25,018 			24,877 			
Industrial		22,432 			23,289 			23,908 			
Miscellaneous		749 			779 			760 			
Total Retail (a)		73,697 			75,493 			76,587 			
								
Wholesale (b)		1,859 			2,335 			2,441 			
								
Total KWhs		75,556 			77,828 			79,028 			

(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold into PJM.

88

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 Transmission and Distribution Utilities	
							
		Years Ended December 31,	
		2020		2019		2018	
		(in degree days)	
Eastern Region							
Actual – Heating (a)		2,743 			3,071 			3,357 		
Normal – Heating (b)		3,202 			3,208 			3,215 		
							
Actual – Cooling (c)		1,140 			1,224 			1,402 		
Normal – Cooling (b)		1,006 			992 			980 		
							
Western Region							
Actual – Heating (a)		189 			301 			354 		
Normal – Heating (b)		313 			322 			325 		
							
Actual – Cooling (d)		2,846 			2,989 			2,861 		
Normal – Cooling (b)		2,711 			2,699 			2,688 		

(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.

89

2020 Compared to 2019
 
Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)

Year Ended December 31, 2019		$	451.0 		
			
Changes in Gross Margin:			
Retail Margins		90.4 		
Margins from Off-system Sales		(39.3)		
Transmission Revenues		44.2 		
Other Revenues		(55.0)		
Total Change in Gross Margin		40.3 		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		52.7 		
Asset Impairments and Other Related Charges		32.5 		
Depreciation and Amortization		38.4 		
Taxes Other Than Income Taxes		(11.7)		
Interest and Investment Income		(4.2)		
Carrying Costs Income		0.6 		
Allowance for Equity Funds Used During Construction		(1.5)		
Non-Service Cost Components of Net Periodic Benefit Cost		(0.9)		
Interest Expense		(45.9)		
Total Change in Expenses and Other		60.0 		
			
Income Tax Expense		(54.9)		
			
Year Ended December 31, 2020		$	496.4 		

The major components of the increase 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 $90 million primarily due to the following:
•A $69 million net increase related to other various rider revenues in Ohio. This increase was partially offset in other expense items below.
•A $61 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.
•A $30 million increase due to a provision for refund recorded in December 2019 as part of the 2019 Texas base rate case.
•A $16 million increase from interim rate increases driven by increased distribution investment in Texas.
•A $13 million increase due to new base rates implemented in June 2020 in Texas.
•A $12 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $9 million increase in weather-normalized margins primarily in the residential class and partially offset in the industrial and commercial classes.
•A $6 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.
•A $5 million increase due to the change in the recording of merger savings as authorized by the PUCT in the most recent base rate case.
These increases were partially offset by:
•A $58 million decrease due to a reversal of a regulatory provision in Ohio in the first quarter of 2019.
•A $38 million decrease due to refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was offset in Income Tax Expense below.
90

•A $17 million net decrease in margin in Ohio for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.
•A $17 million decrease in weather-related usage in Texas primarily due to a 5% decrease in cooling degree days.
•A $6 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.
•Margins from Off-system Sales decreased $39 million primarily due to the following:
•A $52 million decrease in Texas due to lower Oklaunion Power Station PPA revenues. This decrease was offset in Other Operation and Maintenance expenses below.
•A $17 million decrease in sales in Ohio due to lower market prices and decreased sales volumes in 2020. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
•A $26 million increase in Ohio due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above.
•Transmission Revenues increased $44 million primarily due to the following:
•A $48 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $16 million increase in Ohio due to the annual transmission formula rate true-up.
•A $6 million increase due to additional investment in transmission assets in Ohio.
These increases were partially offset by:
•A $14 million decrease in Texas due to a one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This decrease was offset in Income Tax Expense below.
•A $12 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease is offset in Other Revenues below.
•Other Revenues decreased $55 million primarily due to the following:
•A $96 million decrease in securitization revenue due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Depreciation and Amortization expenses and Interest Expense below.
This decrease was partially offset by:
•A $19 million increase in Ohio primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.
•An $18 million increase in revenues due to the amortization of a provision for refund recorded in December 2019 as part of the most recent base rate case in Texas. This increase was offset in Retail Margins and Transmission Revenues above.

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

•Other Operation and Maintenance expenses decreased $53 million primarily due to the following:
•A $67 million decrease due to prior year partial amortization of the AEP Texas Storm Restoration Securitization regulatory asset as a result of the AEP Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This decrease was offset in Income Tax Expense below.
•An $18 million decrease in distribution expenses primarily due to vegetation management. This decrease was partially offset in Retail Margins above.
•A $17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins from Off-System Sales above.
•A $16 million decrease in affiliated PPA expenses in Texas. This decrease was offset in Margins from Off-system Sales above.
•A $12 million decrease due to a charitable contribution to the AEP Foundation in 2019.
•A $7 million decrease in customer-related expenses.
•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
•A $62 million net increase in PJM transmission expenses, primarily due to a $94 million increase in recoverable expenses, partially offset by a $28 million decrease related to the annual transmission formula rate true-up. This increase was offset in Gross Margin above.
91

•A $19 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.
•A $17 million increase in ERCOT transmission expenses. This increase was partially offset in Gross Margin above.
•Asset Impairments and Other Related Charges decreased $33 million due to prior year regulatory disallowances in the 2019 Texas Base Rate Case.
•Depreciation and Amortization expenses decreased $38 million primarily due to the following:
•An $87 million decrease in securitization amortizations due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above and Interest Expense below.
•A $24 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.
These decreases were partially offset by:
•A $31 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•A $22 million increase in Ohio recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•An $11 million increase due to lower deferred equity amortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio which ended in the second quarter of 2019.
•A $6 million increase due to prior year under-recovery of revenues in Ohio associated with the Deferred Asset Phase-In-Recovery securitization which ended in the 2nd quarter of 2019. This decrease was offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $12 million primarily due to the following:
•A $19 million increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
This increase was partially offset by:
•A $6 million decrease in excise taxes due to lower demand in 2020 in Ohio. This decrease was offset in Retail Margins above.
•Interest Expense increased $46 million primarily due to the following:
•A $32 million increase due to higher long-term debt balances.
•A $22 million increase due to the prior year deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.
•An $8 million increase due to due to a decrease in the debt component of AFUDC.
These increases were partially offset by:
•An $8 million decrease in expense related to securitization assets. This decrease was offset above in Other Revenues and Depreciation and Amortization expenses.
•A $6 million decrease due to lower short-term debt balances.
•Income Tax Expense increased $55 million primarily due to an increase in pretax book income and a decrease in Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in 2019. The decrease in Excess ADIT not subject to normalization requirements was partially offset in Gross Margins and Other Operation and Maintenance Expenses above.
92

AEP TRANSMISSION HOLDCO

(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

		Years Ended December 31,	
AEP Transmission Holdco		2020		2019		2018	
		(in millions)	
Transmission Revenues		$	1,198.8 			$	1,073.2 			$	804.1 		
Other Operation and Maintenance		119.0 			119.0 			105.6 		
Depreciation and Amortization		257.6 			183.4 			137.8 		
Taxes Other Than Income Taxes		211.0 			174.4 			142.3 		
Operating Income		611.2 			596.4 			418.4 		

Interest and Investment Income		2.9 			3.4 			2.1 		
Allowance for Equity Funds Used During Construction		74.0 			84.3 			67.2 		
Non-Service Cost Components of Net Periodic Benefit Cost		2.0 			2.7 			2.6 		
Interest Expense		(133.2)			(103.3)			(90.7)		
Income Before Income Tax Expense and Equity Earnings		556.9 			583.5 			399.6 		
Income Tax Expense		130.8 			136.2 			95.3 		
Equity Earnings of Unconsolidated Subsidiary		82.4 			72.8 			68.7 		
Net Income		508.5 			520.1 			373.0 		
Net Income Attributable to Noncontrolling Interests		3.7 			3.8 			3.1 		
Earnings Attributable to AEP Common Shareholders		$	504.8 			$	516.3 			$	369.9 		
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Summary of Investment in Transmission Assets for AEP Transmission Holdco

		December 31,	
		2020		2019		2018	
		(in millions)	
Plant in Service		$	10,327.5 			$	8,812.2 			$	7,008.4 		
Construction Work in Progress		1,499.7 			1,521.8 			1,651.1 		
Accumulated Depreciation and Amortization		595.7 			418.9 			282.8 		
Total Transmission Property, Net		$	11,231.5 			$	9,915.1 			$	8,376.7 		

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2020 Compared to 2019
 
Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)

Year Ended December 31, 2019		$	516.3 		
			
Changes in Transmission Revenues:			
Transmission Revenues		125.6 		
Total Change in Transmission Revenues		125.6 		
			
Changes in Expenses and Other:			
	
Depreciation and Amortization		(74.2)		
Taxes Other Than Income Taxes		(36.6)		

Other Income		(0.5)		
Allowance for Equity Funds Used During Construction		(10.3)		
Non-Service Cost Components of Net Periodic Pension Cost		(0.7)		
Interest Expense		(29.9)		
Total Change in Expenses and Other		(152.2)		
			
Income Tax Expense		5.4 		
Equity Earnings of Unconsolidated Subsidiary		9.6 		
Net Income Attributable to Noncontrolling Interests		0.1 		
			
Year Ended December 31, 2020		$	504.8 		

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

•Transmission Revenues increased $126 million primarily due to the following:
•A $208 million increase due to continued investment in transmission assets.
This increase was partially offset by the following:
•A $65 million decrease as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across affiliated load-serving entities.
•A $17 million decrease as a result of the nonaffiliated annual transmission formula rate true-up.

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

•Depreciation and Amortization expenses increased $74 million primarily due to a higher depreciable base and an increase in depreciation rates as a result of regulatory orders in 2020 in Indiana, Virginia and Michigan.
•Taxes Other Than Income Taxes increased $37 million primarily due to higher property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During Construction decreased $10 million primarily due to the following:
•A $13 million decrease due to lower CWIP.
•A $12 million decrease driven by the favorable impact of a FERC settlement agreement recorded in 2019.
These decreases were partially offset by:
•A $13 million increase driven by FERC audit findings recorded in 2019.
•Interest Expense increased $30 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $5 million primarily due to lower pretax book income and an increase in amortization of Excess ADIT.
•Equity Earnings of Unconsolidated Subsidiary increased $10 million primarily due to higher pretax equity earnings at PATH-WV and ETT.
95

GENERATION & MARKETING

(a)Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

		Years Ended December 31,	
Generation & Marketing		2020		2019		2018	
		(in millions)	
Revenues		$	1,725.6 			$	1,857.6 			$	1,940.3 		
Fuel, Purchased Electricity and Other		1,403.6 			1,456.2 			1,537.3 		
Gross Margin		322.0 			401.4 			403.0 		
Other Operation and Maintenance		124.9 			223.8 			229.3 		
Asset Impairments and Other Related Charges		— 			31.0 			47.7 		
	
Depreciation and Amortization		72.8 			69.5 			41.0 		
Taxes Other Than Income Taxes		13.2 			15.6 			13.4 		
Operating Income		111.1 			61.5 			71.6 		
Interest and Investment Income		3.2 			7.7 			13.1 		
	
Non-Service Cost Components of Net Periodic Benefit Cost		15.4 			14.9 			15.2 		
Interest Expense		(24.0)			(30.0)			(14.9)		
Income Before Income Tax Benefit and Equity Earnings (Loss)		105.7 			54.1 			85.0 		
Income Tax Benefit		(108.0)			(53.8)			(49.2)		
Equity Earnings (Loss) of Unconsolidated Subsidiaries		3.2 			(3.8)			0.5 		
Net Income		216.9 			104.1 			134.7 		
Net Loss Attributable to Noncontrolling Interests		(10.0)			(8.7)			(0.6)		
Earnings Attributable to AEP Common Shareholders		$	226.9 			$	112.8 			$	135.3 		

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Summary of MWhs Generated for Generation & Marketing	
						
	Years Ended December 31,	
	2020		2019		2018	
	(in millions of MWhs)	
Fuel Type:						
Coal	4 			6 			8 		
	
Renewables	3 			2 			1 		
Total MWhs	7 			8 			9 		

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2020 Compared to 2019
 
Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)

Year Ended December 31, 2019		$	112.8 		
			
Changes in Gross Margin:			
Merchant Generation		(78.2)		
Renewable Generation		9.7 		
Retail, Trading and Marketing		(10.9)		
Total Change in Gross Margin		(79.4)		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		98.9 		
Asset Impairments and Other Related Charges		31.0 		
	
Depreciation and Amortization		(3.3)		
Taxes Other Than Income Taxes		2.4 		
Interest and Investment Income		(4.5)		
	
Non-Service Cost Components of Net Periodic Benefit Cost		0.5 		
Interest Expense		6.0 		
Total Change in Expenses and Other		131.0 		
			
Income Tax Benefit		54.2 		
Equity Earnings of Unconsolidated Subsidiaries		7.0 		
Net Loss Attributable to Noncontrolling Interests		1.3 		
			
Year Ended December 31, 2020		$	226.9 		

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 decreased $78 million primarily due to the reduction of capacity revenues and energy margins in 2020 and the retirement of the Conesville Plant, Units 5 and 6 in 2019, Unit 4 in 2020 and the Oklaunion Power Station in 2020.
•Renewable Generation increased $10 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in-service.
•Retail, Trading and Marketing decreased $11 million primarily due to lower retail margins.

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

•Other Operation and Maintenance expenses decreased $99 million primarily due to following:
•A $36 million decrease due to the retirements of Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020.
•A $34 million decrease due to a gain recorded on the sale of land.
•An $18 million decrease related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision.
•An $11 million decrease primarily in employee expenses due to the sale of the Stuart Plant in 2019.
•Asset Impairments and Other Related Charges decreased $31 million primarily due to impairment charges related to the Conesville Plant in 2019.
•Depreciation and Amortization expenses increased $3 million primarily due to a higher depreciable base from increased investments in renewable energy sources.
98

•Interest and Investment Income decreased $5 million due to lower returns on investments.
•Interest Expense decreased $6 million primarily due lower borrowing costs in 2020.
•Income Tax Benefit increased $54 million primarily due to the realization of tax benefit related to the 5-year NOL carryback provision of the CARES Act and an increase in PTCs. This decrease was partially offset by an increase in pretax book income.
•Equity Earnings of Unconsolidated Subsidiaries increased $7 million primarily due to the Sempra Renewables LLC acquisition.

99

CORPORATE AND OTHER

2020 Compared to 2019

Earnings attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $141 million in 2019 to a loss of $90 million in 2020 primarily due to:

•A $32 million decrease in tax expense primarily due to the following:
•A $21 million decrease in state income tax expense related to unitary state filing requirements.
•A $5 million decrease in permanent tax expense.
•A $3 million decrease due to a favorable true-up related to the 2019 federal income tax return.
•A $2 million decrease due to the realization of tax benefit related to the 5-year NOL carryback provision of the CARES Act.
•A $32 million gain on the valuation of common share warrants for an interest in a privately held investee.
•A $5 million write-off of an equity investment and related assets in 2019.

These items were partially offset by:

•A $12 million decrease in interest income from affiliates.
•A $7 million increase in general corporate expenses.

AEP SYSTEM INCOME TAXES

2020 Compared to 2019

Income Tax Expense increased $53 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income. This increase is partially offset by the recognition of tax benefit related to the 5-year NOL carryback provision as a result of the CARES Act, an increase in PTCs and a decrease in state tax expense.
100

FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

		December 31,	
		2020		2019	
		(dollars in millions)	
Long-term Debt, including amounts due within one year		$	31,072.5 			57.2 	%		$	26,725.5 			54.1 	%	
Short-term Debt		2,479.3 			4.6 			2,838.3 			5.7 		
Total Debt		33,551.8 			61.8 			29,563.8 			59.8 		
AEP Common Equity		20,550.9 			37.8 			19,632.2 			39.6 		
Noncontrolling Interests		223.6 			0.4 			281.0 			0.6 		
Total Debt and Equity Capitalization		$	54,326.3 			100.0 	%		$	49,477.0 			100.0 	%	

AEP’s ratio of debt-to-total capital increased from 59.8% to 61.8% as of December 31, 2019 and 2020, respectively, primarily due to an increase in debt to support 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 December 31, 2020, AEP had a $4 billion revolving credit facility 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 resulting in higher commercial paper cost and limited access. To address these issues and the uncertainty around COVID-19, in March 2020, AEP entered into a $1 billion 364-day Term Loan and borrowed the full amount. In November 2020, AEP repaid the 364-day Term Loan.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of December 31, 2020, available liquidity was approximately $2.5 billion as illustrated in the table below:

		Amount		Maturity	
		(in millions)			
Commercial Paper Backup:					
Revolving Credit Facility		$	4,000.0 			June 2022	

Cash and Cash Equivalents		392.7 				
Total Liquidity Sources		4,392.7 				
Less: AEP Commercial Paper Outstanding		1,852.3 				
					
Net Available Liquidity		$	2,540.4 				

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 2020 was $3 billion.  The weighted-average interest rate for AEP’s commercial paper during 2020 was 1.28%.

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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 million.  The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2020, was $180 million with maturities ranging from January 2021 to December 2021.

Financing Plan

As of December 31, 2020, AEP had $2.1 billion of long-term debt due within one year. This included $235 million of Pollution Control Bonds with mandatory tender dates and credit support for variable interest rates that requires the debt be classified as current and $190 million of securitization bonds and DCC Fuel notes.  Management plans to refinance the majority of the maturities due within one year on a long-term basis.

Securitized Accounts Receivables

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

In May 2020, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As of December 31, 2020, 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. The receivables that are ineligible under the receivables securitization agreement are financed with short-term debt at AEP Credit.

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 December 31, 2020, this contractually-defined percentage was 58.6%. 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 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.

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.
102

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 recent acquisition of Sempra Renewables LLC.

See Note 14 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.74 per-share in January 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 14 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.

		Years Ended December 31,	
		2020		2019		2018	
		(in millions)	
Cash, Cash Equivalents and Restricted Cash at Beginning of Period		$	432.6 			$	444.1 			$	412.6 		
Net Cash Flows from Operating Activities		3,832.9 			4,270.1 			5,223.2 		
Net Cash Flows Used for Investing Activities		(6,233.9)			(7,144.5)			(6,353.6)		
Net Cash Flows from Financing Activities		2,406.7 			2,862.9 			1,161.9 		
	
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash		5.7 			(11.5)			31.5 		
Cash, Cash Equivalents and Restricted Cash at End of Period		$	438.3 			$	432.6 			$	444.1 		

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Operating Activities

		Years Ended December 31,	
		2020		2019		2018	
		(in millions)	
Net Income		$	2,196.7 			$	1,919.8 			$	1,931.3 		
Non-Cash Adjustments to Net Income (a)		2,946.3 			2,685.7 			2,400.0 		
Mark-to-Market of Risk Management Contracts		66.5 			(29.2)			(66.4)		
Pension Contributions to Qualified Plan Trust		(110.3)			— 			— 		
Property Taxes		(43.3)			(73.8)			(59.1)		
Deferred Fuel Over/Under Recovery, Net		(31.8)			85.2 			189.7 		
Change in Regulatory Assets		(337.9)			49.5 			354.1 		

Change in Other Noncurrent Assets		(142.5)			(112.8)			(172.1)		
Change in Other Noncurrent Liabilities		(54.5)			(116.1)			129.0 		
Change in Certain Components of Working Capital		(656.3)			(138.2)			516.7 		
Net Cash Flows from Operating Activities		$	3,832.9 			$	4,270.1 			$	5,223.2 		

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Rockport Plant Unit 2 Operating Lease Amortization, Deferred Income Taxes, Asset Impairments and Other Related Charges, Allowance for Equity Funds Used During Construction, Amortization of Nuclear Fuel and Pension and Postemployment Benefit Reserves.

2020 Compared to 2019

Net Cash Flows from Operating Activities decreased by $437 million primarily due to the following:
•A $518 million decrease in cash from Changes in Certain Components of Working Capital. This decrease is primarily due to an increase in accounts receivable driven by increased sales in December 2020 and increased days sales outstanding.
•A $387 million decrease in cash from Changes in Regulatory Assets primarily due to deferred storm costs related to Hurricanes Laura and Delta, the establishment of regulatory assets as a result of the Virginia SCC order issued in the 2017-2019 Virginia Triennial Review and the settlement of deferred restoration costs from the Texas Storm Cost Securitization financing order received in 2019. See Note 4 - Rate Matters and Note 5 - Effects of Regulation for additional information.
•A $117 million decrease in cash from Deferred Fuel Over/Under Recovery, Net primarily due to an increase in the under recovered fuel balances at PSO.
•A $110 million decrease in cash due to a discretionary contribution to the qualified pension plan. See Note 8 - Benefit Plans for additional information.
These decreases in cash were partially offset by:
•A $538 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.
•A $96 million increase in the fair value of risk management contracts due to pricing movement in the commodities markets.

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Investing Activities

		Years Ended December 31,	
		2020		2019		2018	
		(in millions)	
Construction Expenditures		$	(6,246.3)			$	(6,051.4)			$	(6,310.9)		
Acquisitions of Nuclear Fuel		(69.7)			(92.3)			(46.1)		
Acquisition of Sempra Renewables LLC and Santa Rita East, net of cash and restricted cash acquired		— 			(918.4)			— 		
	
Other		82.1 			(82.4)			3.4 		
Net Cash Flows Used for Investing Activities		$	(6,233.9)			$	(7,144.5)			$	(6,353.6)		

2020 Compared to 2019

Net Cash Flows Used for Investing Activities decreased by $911 million primarily due to the following:
•A $918 million decrease due to the acquisition of Sempra Renewables LLC and Santa Rita East. The $918 million represents a cash payment of $936 million, net of cash and restricted cash acquired of $18 million. See Note 7 - Acquisitions, Dispositions and Impairments for additional information.
This decrease in the use of cash was partially offset by:
•A $195 million increase in construction expenditures primarily due to increases in Transmission Operations of $190 million and Generation & Marketing of $110 million, partially offset by a decrease in Vertically Integrated of $146 million.

Financing Activities

		Years Ended December 31,	
		2020		2019		2018	
		(in millions)	
Issuance of Common Stock		$	155.0 			$	65.3 			$	73.6 		
Issuance/Retirement of Debt, Net		3,927.3 			4,244.1 			2,435.1 		
	
Dividends Paid on Common Stock		(1,424.9)			(1,350.0)			(1,255.5)		
Redemption of Noncontrolling Interests		(100.2)			— 			— 		
Other		(150.5)			(96.5)			(91.3)		
Net Cash Flows from Financing Activities		$	2,406.7 			$	2,862.9 			$	1,161.9 		

2020 Compared to 2019

Net Cash Flows from Financing Activities decreased by $456 million primarily due to the following:
•A $1.3 billion decrease in short-term debt primarily due to increased repayments of commercial paper. See Note 14 - Financing Activities for additional information.
•A $119 million decrease due to increased retirements of long-term debt. See Note 14 - Financing Activities for additional information.
•A $100 million decrease due to the redemption of noncontrolling interests in Desert Sky Wind Farm LLC and Trent Wind Farm LLC as well as the acquisition of an additional 10% interest in Santa Rita East. See Note 7 - Acquisitions, Dispositions and Impairments for additional information.
These decreases in cash were partially offset by:
•A $1.1 billion increase in issuances of long-term debt. See Note 14 - Financing Activities for additional information.
105

The following financing activities occurred during 2020:

AEP Common Stock:

•During 2020, AEP issued 2.4 million shares of common stock under the incentive compensation, employee saving and dividend reinvestment plans and received net proceeds of $155 million.

Debt:

•During 2020, AEP issued approximately $5.6 billion of long-term debt, including $4.4 billion of senior unsecured notes at interest rates ranging from 0.75% to 3.7%, $850 million of junior subordinated debenture notes at an interest rate of 1.3%, $175 million of pollution control bonds at interest rates ranging from 0.625% to 1.00%, and $238 million of other debt at various interest rates.  The proceeds from these issuances were used to fund long-term debt maturities and construction programs.
•During 2020, AEP entered into interest rate derivatives with notional amounts totaling $1.8 billion that were designated as either fair value or cash flow hedges.  During 2020, settlements of AEP’s interest rate derivatives resulted in net cash received of $59 million for derivatives designated as fair value hedges and net cash paid of $38 million for derivatives designated as cash flow hedges.  As of December 31, 2020, AEP had a total notional amount of $950 million of outstanding interest rate derivatives designated as fair value hedges and $200 million designated as cash flow hedges.

See “Long-term Debt Subsequent Events” section of Note 14 for Long-term debt and other securities issued, retired and principal payments made after December 31, 2020 through February 25, 2021, the date that the 10-K was issued.

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $7.5 billion of capital expenditures in 2021.  For the four year period, 2022 through 2025, management forecasts capital expenditures 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. The 2021 estimated capital expenditures include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:

		2021 Budgeted Capital Expenditures	
Segment		Environmental		Generation		Renewables		Transmission		Distribution		Other (a)		Total	
		(in millions)	
Vertically Integrated Utilities		$	124.7 			$	264.7 			$	711.3 			$	787.1 			$	1,040.5 			$	364.3 			$	3,292.6 		
Transmission and Distribution Utilities		— 			— 			— 			833.9 			977.3 			233.1 			2,044.3 		
AEP Transmission Holdco		— 			— 			— 			1,564.5 			— 			32.8 			1,597.3 		
Generation & Marketing		9.1 			39.9 			434.1 			— 			— 			17.7 			500.8 		
Corporate and Other		— 			— 			— 			— 			— 			31.8 			31.8 		
Total		$	133.8 			$	304.6 			$	1,145.4 			$	3,185.5 			$	2,017.8 			$	679.7 			$	7,466.8 		

(a)Amount primarily consists of facilities, software and telecommunications.

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The 2021 estimated capital expenditures by Registrant Subsidiary include distribution, transmission and generation-related investments, as well as expenditures for compliance with environmental regulations as follows:

		2021 Budgeted Capital Expenditures	
Company		Environmental		Generation		Renewables		Transmission		Distribution		Other (a)		Total	
		(in millions)	
AEP Texas		$	— 			$	— 			$	— 			$	606.8 			$	513.7 			$	104.8 			$	1,225.3 		
AEPTCo		— 			— 			— 			1,451.7 			— 			33.4 			1,485.1 		
APCo		60.6 			64.1 			1.0 			309.6 			341.8 			100.7 			877.8 		
I&M		16.8 			75.9 			1.3 			98.3 			268.1 			114.4 			574.8 		
OPCo		— 			— 			— 			227.1 			463.6 			128.3 			819.0 		
PSO		— 			42.5 			322.3 			102.3 			210.7 			48.5 			726.3 		
SWEPCo		8.8 			43.9 			386.7 			205.4 			135.8 			67.1 			847.7 		

(a) Amount primarily consists of facilities, software and telecommunications.

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CYBER SECURITY

The electric utility industry is an identified critical infrastructure function with mandatory cyber security requirements under the authority of FERC. The NERC, which FERC certified as the nation’s Electric Reliability Organization, developed mandatory critical infrastructure protection cyber security reliability standards. AEP’s service territory covers multiple NERC regions, and is audited at least annually by one or more of the regions. AEP began participating in the NERC grid security and emergency response exercises, GridEx, in 2013 and continues to participate in the bi-yearly exercises. These efforts, led by NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid. The operations of AEP’s electric utility subsidiaries are subject to extensive and rigorous mandatory cyber and physical security requirements that are developed and enforced by NERC to protect grid security and reliability. AEP’s Enterprise Security program uses the National Institute of Standards and Technology Cybersecurity Framework as a guideline. AEP’s Chief Security Officer (CSO) is also its NERC Critical Infrastructure Protection Senior Manager, ensuring alignment of compliance with the enterprise security program.

Critical cyber assets, such as data centers, power plants, transmission operations centers and business networks are protected using multiple layers of cyber security controls and authentication. Cyber hackers have been successful in breaching a number of very secure facilities, including federal agencies, banks and retailers. As understanding of these events develop, AEP has adopted a defense in depth approach to cyber security and continually assesses its cyber security tools and processes to determine where to strengthen its defenses. These strategies include monitoring, alerting and emergency response, forensic analysis, disaster recovery, threat sharing and criminal activity reporting. This approach has allowed AEP to deal with threats in real-time and to limit the impact of cyber and related events to levels that would be expected in the ordinary course of business in the absence of such activity.

AEP has undertaken a variety of actions to monitor and address cyber-related risks. Cyber security and the effectiveness of AEP’s cyber security processes are reviewed annually with the Board of Directors and at several meetings with the Audit Committee throughout the year. AEP’s Chief Executive Officer and Executive team participate in interactive threat briefings from AEP’s CSO and cyber security team on a monthly basis. AEP’s strategy for managing cyber-related risks is integrated within its enterprise risk management processes. AEP enterprise security continually adjusts staff and resources in response to the evolving threat landscape. In addition, AEP maintains cyber liability insurance to cover certain damages caused by cyber incidents.

AEP’s CSO leads the cyber security and physical security teams and is responsible for the design, implementation and execution of AEP’s security risk management strategy, which includes cyber security. AEP’s cyber security team operates a 24/7 Cyber Security Intelligence and Response Center responsible for monitoring the AEP System for cyber risks and threats. Under the direction of the CSO, the cyber security team actively monitors best practices, performs penetration testing, leads response exercises and internal campaigns and provides training and communication across the organization.

The cyber security team constantly scans the AEP System for risks and threats. AEP also continually reviews its business continuity plan to develop an effective recovery strategy that seeks to decrease response times, limit financial impacts and maintain customer confidence during any business interruption. AEP has implemented a third-party risk governance program to identify potential risks introduced through third-party relationships, such as vendors, software and hardware manufacturers or professional service providers. As warranted, AEP obtains certain contractual security guarantees and assurances with these third-party relationships to help ensure the security and safety of its information. The cyber security team works closely with a broad range of departments, including legal, regulatory, corporate communications and audit services and information technology.

The cyber security team collaborates with partners from both industry and government, and routinely participates in industry-wide programs that exchange knowledge of threats with utility peers, industry and federal agencies. AEP is an active member of a number of industry specific threat and information sharing communities including the Department of Homeland Security and the Electricity Information Sharing and Analysis Center. AEP continues to work with nonaffiliated entities to do penetration testing and to design and implement appropriate remediation strategies. There can be no assurance, however, that these efforts will be effective to prevent interruption of services or other damages to AEP's business or operations in connection with any cyber-related incident.
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CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies.  Management considers an accounting estimate to be critical if:

•It requires assumptions to be made that were uncertain at the time the estimate was made; and
•Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition.

Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosures relating to them.

Management believes that the current assumptions and other considerations used to estimate amounts reflected in the financial statements are appropriate.  However, actual results can differ significantly from those estimates.

The sections that follow present information about critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.

Regulatory Accounting

Nature of Estimates Required

The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.

The Registrants recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation.  Specifically, the timing of expense and income recognition is matched with regulated revenues.  Liabilities are also recorded for refunds, or probable refunds, to customers that have not been made.

Assumptions and Approach Used

When incurred costs are probable of recovery through regulated rates, regulatory assets are recorded on the balance sheets.  Management reviews the probability of recovery at each balance sheet date and whenever new events occur.  Similarly, regulatory liabilities are recorded when a determination is made that a refund is probable or when ordered by a commission.  Examples of new events that affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation.  The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs as well as the return of revenues, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates.  If recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings.  A write-off of regulatory assets or establishment of a regulatory liability may also reduce future cash flows since there will be no recovery through regulated rates.

Effect if Different Assumptions Used

A change in the above assumptions may result in a material impact on net income.  See Note 5 - Effects of Regulation for additional information related to regulatory assets and regulatory liabilities.
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Revenue Recognition – Unbilled Revenues

Nature of Estimates Required

AEP recognizes revenues from customers as the performance obligations of delivering energy to customers are satisfied.  The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded.  This estimate is reversed in the following month and actual revenue is recorded based on meter readings.  PSO and SWEPCo do not include the fuel portion in unbilled revenue in accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas.

Accrued unbilled revenues for the Vertically Integrated Utilities segment were $288 million and $248 million as of December 31, 2020 and 2019, respectively. The changes in unbilled electric utility revenues for AEP’s Vertically Integrated Utilities segment were $40 million, $(7) million and $(23) million for the years ended December 31, 2020, 2019 and 2018, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather and rates.  

Accrued unbilled revenues for the Transmission and Distribution Utilities segment were $171 million and $166 million as of December 31, 2020 and 2019, respectively. The changes in unbilled electric utility revenues for AEP’s Transmission and Distribution Utilities segment were $5 million, $(12) million and $(24) million for the years ended December 31, 2020, 2019 and 2018, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather and rates.  

Accrued unbilled revenues for the Generation & Marketing segment were $86 million and $75 million as of December 31, 2020 and 2019, respectively. The changes in unbilled electric utility revenues for AEP’s Generation & Marketing segment were $11 million, $16 million and $5 million for the years ended December 31, 2020, 2019 and 2018, respectively.  

Assumptions and Approach Used

For each Registrant except AEPTCo, the monthly estimate for unbilled revenues is based upon a primary computation of net generation (generation plus purchases less sales) less the current month’s billed KWh and estimated line losses, plus the prior month’s unbilled KWh. However, due to the potential for meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon an allocation of billed KWh to the current month and previous month, on a billing cycle-by-cycle basis, and by dividing the current month aggregated result by the billed KWh. The two methodologies are evaluated to confirm that they are not statistically different.

For AEP’s Generation & Marketing segment, management calculates unbilled based on a primary computation of load as provided by PJM less the current month’s billed KWh and estimated line losses, plus the prior month’s unbilled KWh. However, due to the potential for meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon using the most recent historic daily activity on a per contract basis. The two methodologies are evaluated to confirm that they are not statistically different.

Effect if Different Assumptions Used

If the two methodologies used to estimate unbilled revenue are statistically different, a limiter adjustment is made to bring the primary computation within one standard deviation of the secondary computation. Additionally, significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the estimate of unbilled revenue.  

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Accounting for Derivative Instruments

Nature of Estimates Required

Management considers fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates.  These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.

Assumptions and Approach Used

The Registrants measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based primarily on exchange prices and broker quotes.  If a quoted market price is not available, the fair value is estimated based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions.  Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment.  These uncertainties include projections of future commodity prices, including future price volatility.

The Registrants reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality.  Liquidity adjustments are calculated by utilizing bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time.  Credit adjustments on risk management contracts are calculated using estimated default probabilities and recovery rates relative to the counterparties or counterparties with similar credit profiles and contractual netting agreements.

With respect to hedge accounting, management assesses hedge effectiveness and evaluates a forecasted transaction’s probability of occurrence within the specified time period as provided in the original hedge documentation.

Effect if Different Assumptions Used

There is inherent risk in valuation modeling given the complexity and volatility of energy markets.  Therefore, it is possible that results in future periods may be materially different as contracts settle.

The probability that hedged forecasted transactions will not occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into operating income.

For additional information see Note 10 - Derivatives and Hedging and Note 11 - Fair Value Measurements.  See “Fair Value Measurements of Assets and Liabilities” section of Note 1 for AEP’s fair value calculation policy.

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Long-Lived Assets

Nature of Estimates Required

In accordance with the requirements of “Property, Plant and Equipment” accounting guidance and “Regulated Operations” accounting guidance, the Registrants evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable. Such events or changes in circumstance include planned abandonments, probable disallowances for rate-making purposes of assets determined to be recently completed plant, and assets that meet the held-for-sale criteria.  The Registrants utilize a group composite method of depreciation to estimate the useful lives of long-lived assets.  

An impairment evaluation of a long-lived, held and used asset may result from an abandonment, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses.  If the carrying amount of the asset is not recoverable, the Registrants record an impairment to the extent that the fair value of the asset is less than its book value.  Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets and developing the non-discounted and discounted future cash flows (used to estimate fair value in the absence of market-based value, in some instances) associated with the asset.  Assets held for sale must be measured at the lower of the book value or fair value less cost to sell. An impairment is recognized if an asset’s fair value less costs to sell is less than its book value. Any impairment charge is recorded as a reduction to earnings.

Assumptions and Approach Used

The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, the Registrants estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals.  Cash flow estimates are based on relevant information available at the time the estimates are made.  Estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.  Also, when measuring fair value, management evaluates the characteristics of the asset or liability to determine if market participants would take those characteristics into account when pricing the asset or liability at the measurement date.  Such characteristics include, for example, the condition and location of the asset or restrictions on the use of the asset.  The Registrants perform depreciation studies that include a review of any external factors that may affect the useful life to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions for regulated assets.  The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Effect if Different Assumptions Used

In connection with the evaluation of long-lived assets in accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the fair value of the asset can vary if different estimates and assumptions are used in the applied valuation techniques.  Estimates for depreciation rates contemplate the history of interim capital replacements and the amount of salvage expected.  In cases of impairment, the best estimate of fair value was made using valuation methods based on the most current information at that time.  Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, the timing and terms of the transactions and management’s analysis of the benefits of the transaction.

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Pension and OPEB

AEP maintains a qualified, defined benefit pension plan (Qualified Plan), which covers substantially all nonunion and certain union employees, and unfunded, non-qualified supplemental plans (Nonqualified Plans) to provide benefits in excess of amounts permitted under the provisions of the tax law for participants in the Qualified Plan (collectively the Pension Plans).  AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees.  The Pension Plans and OPEB plans are collectively referred to as the Plans.

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.  See Note 8 - Benefit Plans for information regarding costs and assumptions for the Plans.

The following table shows the net periodic cost (credit) of the Plans:

		Years Ended December 31,	
Net Periodic Cost (Credit)		2020		2019		2018	
		(in millions)	
Pension Plans		$	108.6 			$	61.5 			$	82.9 		
OPEB		(109.7)			(80.7)			(101.8)		

The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets.  In developing the expected long-term rate of return assumption for 2021, management evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions.  Management also considered historical returns of the investment markets and tax rates which affect a portion of the OPEB plans’ assets.  Management anticipates that the investment managers employed for the Plans will invest the assets to generate future returns averaging 4.75% for the Qualified Plan and 4.75% for the OPEB plans.

The expected long-term rate of return on the Plans’ assets is based on management’s targeted asset allocation and expected investment returns for each investment category.  Assumptions for the Plans are summarized in the following table:

	Pension Plans		OPEB	
			Assumed/				Assumed/	
	2021		Expected		2021		Expected	
	Target		Long-Term		Target		Long-Term	
	Asset		Rate of		Asset		Rate of	
	Allocation		Return		Allocation		Return	
Equity	25 	%		6.79 	%		49 	%		6.45 	%	
Fixed Income	59 			3.30 			49 			3.18 		
Other Investments	15 			7.88 			— 			— 		
Cash and Cash Equivalents	1 			1.21 			2 			1.21 		
Total	100 	%				100 	%			

Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation.  Management believes that 4.75% for the Qualified Plan and 4.75% for the OPEB plans are reasonable estimates of the long-term rate of return on the Plans’ assets.  The Pension Plans’ assets had an actual gain of 16.91% and 15.81% for the year ended December 31, 2020 and 2019, respectively.  The OPEB plans’ assets had an actual gain of 16.33% and 20.93% for the year ended December 31, 2020 and 2019, respectively.  Management will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.
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AEP bases the determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.  Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.  As of December 31, 2020, AEP had cumulative gains of approximately $575 million for the Qualified Plan that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized market-related net actuarial gains may result in decreases in the future pension costs depending on several factors, including whether such gains at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance.

The method used to determine the discount rate that AEP utilizes for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.  The discount rate as of December 31, 2020 under this method was 2.5% for the Qualified Plan, 2.25% for the Nonqualified Plans and 2.55% for the OPEB plans.  Due to the effect of the unrecognized net actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 4.75%, discount rates of 2.5% and 2.25% and various other assumptions, management estimates that the pension costs for the Pension Plans will approximate $137 million, $137 million and $137 million in 2021, 2022 and 2023, respectively.  Based on an expected rate of return on the OPEB plans’ assets of 4.75%, a discount rate of 2.55% and various other assumptions, management estimates OPEB plan credits will approximate $121 million, $120 million and $112 million in 2021, 2022 and 2023, respectively. Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans.  The actuarial assumptions used may differ materially from actual results.  The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below.

The value of AEP’s Pension Plans’ assets increased to $5.6 billion as of December 31, 2020 from $5.0 billion as of December 31, 2019 primarily due to higher investment returns.  During 2020, the Qualified Plan paid $402 million and the Nonqualified Plans paid $5 million in benefits to plan participants.  The value of AEP’s OPEB plans’ assets increased to $1.9 billion as of December 31, 2020 from $1.8 billion as of December 31, 2019 primarily due to higher investment returns.  The OPEB plans paid $131 million in benefits to plan participants during 2020.

Nature of Estimates Required

AEP sponsors pension and OPEB plans in various forms covering all employees who meet eligibility requirements.  These benefits are accounted for under “Compensation” and “Plan Accounting” accounting guidance.  The measurement of pension and OPEB obligations, costs and liabilities is dependent on a variety of assumptions.

Assumptions and Approach Used

The critical assumptions used in developing the required estimates include the following key factors:

•Discount rate
•Compensation increase rate
•Cash balance crediting rate
•Health care cost trend rate
•Expected return on plan assets

Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.
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Effect if Different Assumptions Used

The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants.  These differences may result in a significant impact to the amount of pension and OPEB expense recorded.  If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

		Pension Plans		OPEB	
		+0.5%		-0.5%		+0.5%		-0.5%	
		(in millions)	
Effect on December 31, 2020 Benefit Obligations									
Discount Rate		$	(286.9)			$	316.2 			$	(66.6)			$	73.7 		
Compensation Increase Rate		32.9 			(30.3)			NA		NA	
Cash Balance Crediting Rate		81.2 			(75.4)			NA		NA	
Health Care Cost Trend Rate		NA		NA		12.7 			(11.7)		
									
Effect on 2020 Periodic Cost									
Discount Rate		$	(12.5)			$	13.6 			$	(3.2)			$	3.4 		
Compensation Increase Rate		6.5 			(5.9)			NA		NA	
Cash Balance Crediting Rate		14.1 			(13.2)			NA		NA	
Health Care Cost Trend Rate		NA		NA		0.9 			(0.8)		
Expected Return on Plan Assets		(23.0)			23.0 			(8.7)			8.7 		

NA    Not applicable.

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CONTRACTUAL OBLIGATION INFORMATION

AEP’s contractual cash obligations include amounts reported on the balance sheets and other obligations disclosed in the footnotes.  The following table summarizes AEP’s contractual cash obligations as of December 31, 2020:

Payments Due by Period	
											
Contractual Cash Obligations		Less Than
1 Year		2-3 Years		4-5 Years		After
5 Years		Total	
		(in millions)	
Short-term Debt (a)		$	2,479.3 			$	— 			$	— 			$	— 			$	2,479.3 		
Interest on Fixed Rate Portion of Long-term Debt (b)		1,310.7 			2,373.0 			2,209.0 			14,918.9 			20,811.6 		
Fixed Rate Portion of Long-term Debt (c)		1,533.1 			4,481.8 			2,443.1 			20,599.2 			29,057.2 		
Variable Rate Portion of Long-term Debt (d)		553.0 			1,715.9 			6.6 			— 			2,275.5 		
Finance Lease Obligations (e)		72.2 			120.2 			96.2 			48.9 			337.5 		
Operating Lease Obligations (e)		270.8 			357.5 			149.6 			193.0 			970.9 		
Fuel Purchase Contracts (f)		763.9 			715.1 			212.9 			381.5 			2,073.4 		
Energy and Capacity Purchase Contracts		211.6 			291.8 			277.0 			928.5 			1,708.9 		
Construction Contracts for Capital Assets (g)		1,624.2 			3,211.8 			2,347.4 			4,379.1 			11,562.5 		
Total		$	8,818.8 			$	13,267.1 			$	7,741.8 			$	41,449.1 			$	71,276.8 		

(a)Represents principal only, excluding interest.
(b)Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2020 and do not reflect anticipated future refinancing, early redemptions or debt issuances.
(c)See “Long-term Debt” section of Note 14 for additional information.  Represents principal only, excluding interest.
(d)See “Long-term Debt” section of Note 14 for additional information.  Represents principal only, excluding interest.  Variable rate debt had interest rates that ranged between 0.18% and 2.25% as of December 31, 2020.
(e)See Note 13 - Leases for additional information.
(f)Represents contractual obligations to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.
(g)Represents only capital assets for which there are signed contracts.  Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.

AEP’s pension funding requirements are not included in the above table.  As of December 31, 2020, AEP expects to make contributions to the pension plans totaling $133 million in 2021.  Estimated contributions of $135 million in 2022 and $136 million in 2023 may vary significantly based on market returns, changes in actuarial assumptions and other factors.  Based upon the projected benefit obligation and fair value of assets available to pay pension benefits, the pension plans were 100.2% funded as of December 31, 2020. See “Estimated Future Benefit Payments and Contributions” section of Note 8 for additional information.

In addition to the amounts disclosed in the contractual cash obligations table above, 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.  There is no collateral held in relation to any guarantees in excess of the ownership percentages.  In the event any letters of credit are drawn, there is no recourse to third-parties.  See “Letters of Credit” section of Note 6 for additional information.

SIGNIFICANT TAX LEGISLATION

In March 2020, the CARES Act was signed into law and includes tax relief provisions such as: (a) an AMT Credit Refund, (b) a 5-year NOL carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. See “Federal Tax Legislation” section of Note 12 for additional information.

In December 2020, the CAA of 2021 was signed into law and includes: (a) COVID-19 tax relief and tax extender provisions including, extensions of time to begin construction on and placed in-service assets generating PTCs and ITCs, (b) 100% deductibility of business meals in 2021 and 2022 and (c) an extension of the work opportunity tax credit. See “Federal Tax Legislation” section of Note 12 for additional information.
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ACCOUNTING STANDARDS

See Note 2 - New Accounting Standards for information related to accounting standards adopted in 2020 and standards effective in the future.

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, 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. Also, interest rates could continue to see increased volatility as capital markets confront uncertainty.

117

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

MTM Risk Management Contract Net Assets (Liabilities)	
Year Ended December 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	(44.3)			(7.2)			(17.9)			(69.4)		
Fair Value of New Contracts at Inception When Entered During the Period (a)	— 			— 			15.2 			15.2 		
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)	9.6 			1.3 			— 			10.9 		
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2020	$	41.2 			$	(109.5)			$	168.1 			99.8 		
Commodity Cash Flow Hedge Contracts							(75.4)		
Interest Rate Cash Flow Hedge Contracts							(1.0)		
Fair Value Hedge Contracts							(1.5)		
Collateral Deposits							3.4 		
	
Total MTM Derivative Contract Net Assets as of December 31, 2020							$	25.3 		

(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 10 – Derivatives and Hedging and Note 11 – 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.

118

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 December 31, 2020, credit exposure net of collateral to sub investment grade counterparties was approximately 6.6%, 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 December 31, 2020, 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		$	412.2 			$	— 			$	412.2 			2 			$	198.2 		
Split Rating		1.1 			— 			1.1 			1 			1.1 		
	
No External Ratings:											
Internal Investment Grade		133.8 			— 			133.8 			3 			91.8 		
Internal Noninvestment Grade		49.4 			10.5 			38.9 			2 			25.6 		
Total as of December 31, 2020		$	596.5 			$	10.5 			$	586.0 						

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 December 31, 2020, 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.
119

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

VaR Model
Trading Portfolio

Twelve Months Ended		Twelve Months Ended	
December 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 		

VaR Model
Non-Trading Portfolio

Twelve Months Ended		Twelve Months Ended	
December 31, 2020		December 31, 2019	
End		High		Average		Low		End		High		Average		Low	
(in millions)		(in millions)	
$	2.2 			$	2.9 			$	1.0 			$	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 12 months ended December 31, 2020, 2019 and 2018, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $32 million, $24 million and $25 million, respectively.
120

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
American Electric Power Company, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of income, of comprehensive income (loss), of changes in equity and of cash flows for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in
Internal Control - Integrated Framework (2013) issued by the COSO.

Change in Accounting Principle

As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
121

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, whether influenced by issuance of regulatory commission orders, passage of new legislation, or changes in the regulatory environment. As of December 31, 2020, there were $3.6 billion of deferred costs included in regulatory assets, $0.4 billion of which were pending final regulatory approval, and $8.4 billion of regulatory liabilities awaiting potential refund or future rate reduction, $0.5 billion of which were pending final regulatory determination.

The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and applying guidance contained in rate orders and other relevant evidence; which in turn led to significant audit effort and a high degree of auditor subjectivity in performing procedures and in evaluating audit evidence relating to management’s judgments about the probability of recovery of regulatory assets and refund of regulatory liabilities.

122

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s assessment of regulatory proceedings, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, including those subject to pending rate cases, also involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, and application of regulatory precedents.

Valuation of Level 3 Risk Management Commodity Contracts

As described in Notes 1, 10 and 11 to the consolidated financial statements, the Company employs risk management commodity contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, over-the-counter swaps and options to accomplish its risk management strategies. Certain over-the-counter and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. The fair value of these risk management commodity contracts is estimated based on available market information including valuation models that estimate future energy prices based on existing market and broker quotes, and other assumptions. Fair value estimates involve significant uncertainties and matters of significant judgement including future commodity prices and future price volatility. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. Management utilized such unobservable pricing data to value its Level 3 risk management commodity contract assets and liabilities, which totaled $256.3 million and $174.8 million, as of December 31, 2020, respectively.

The principal considerations for our determination that performing procedures relating to the valuation of Level 3 risk management commodity contracts is a critical audit matter are the significant judgment and estimation by management when developing the fair value of the commodity contracts; which in turn led to significant audit effort and a high degree of auditor subjectivity in performing procedures and in evaluating audit evidence relating to the unobservable assumptions for projections of future commodity prices and future price volatilities used within management’s discounted cash flow models. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in performing these procedures and evaluating the audit evidence obtained.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s valuation of the risk management commodity contracts, including controls over the assumptions used to value the Level 3 risk management commodity contracts. These procedures also included, among others, testing the data used in and management’s process for developing the fair value of the Level 3 risk management commodity contracts. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the discounted cash flow models and reasonableness of the future commodity prices and future price volatilities assumptions.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

We have served as the Company’s auditor since 2017.
123

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of American Electric Power Company, Inc. and Subsidiary Companies (AEP) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  AEP’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of AEP’s internal control over financial reporting as of December 31, 2020.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013).  Based on management’s assessment, management concluded AEP’s internal control over financial reporting was effective as of December 31, 2020.

PricewaterhouseCoopers LLP, AEP’s independent registered public accounting firm has issued an audit report on the effectiveness of AEP’s internal control over financial reporting as of December 31, 2020.  The Report of Independent Registered Public Accounting Firm appears on the previous page.
124

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2020, 2019 and 2018
 (in millions, except per-share and share amounts)

		Years Ended December 31,	
		2020		2019		2018	
REVENUES							
Vertically Integrated Utilities		$	8,753.2 			$	9,245.7 			$	9,556.7 		
Transmission and Distribution Utilities		4,238.7 			4,319.0 			4,552.3 		
Generation & Marketing		1,621.0 			1,721.8 			1,818.1 		
Other Revenues		305.6 			274.9 			268.6 		
TOTAL REVENUES		14,918.5 			15,561.4 			16,195.7 		
EXPENSES							
Fuel and Other Consumables Used for Electric Generation		1,439.3 			1,940.9 			2,359.4 		
Purchased Electricity for Resale		2,930.4 			3,165.2 			3,427.1 		
Other Operation		2,572.4 			2,743.7 			2,979.2 		
Maintenance		1,010.4 			1,213.9 			1,247.4 		
Asset Impairments and Other Related Charges		— 			156.4 			70.6 		
	
Depreciation and Amortization		2,682.8 			2,514.5 			2,286.6 		
Taxes Other Than Income Taxes		1,295.5 			1,234.5 			1,142.7 		
TOTAL EXPENSES		11,930.8 			12,969.1 			13,513.0 		
							
OPERATING INCOME		2,987.7 			2,592.3 			2,682.7 		
							
Other Income (Expense):							

Other Income		57.0 			26.6 			18.2 		
Allowance for Equity Funds Used During Construction		148.1 			168.4 			132.5 		
Non-Service Cost Components of Net Periodic Benefit Cost		119.0 			120.0 			124.5 		
	
Interest Expense		(1,165.7)			(1,072.5)			(984.4)		
							
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS		2,146.1 			1,834.8 			1,973.5 		
							
Income Tax Expense (Benefit)		40.5 			(12.9)			115.3 		
Equity Earnings of Unconsolidated Subsidiaries		91.1 			72.1 			73.1 		

	

NET INCOME		2,196.7 			1,919.8 			1,931.3 		
							
Net Income (Loss) Attributable to Noncontrolling Interests		(3.4)			(1.3)			7.5 		
							
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	2,200.1 			$	1,921.1 			$	1,923.8 		
							
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING		495,718,223 			493,694,345 			492,774,600 		

	
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	4.44 			$	3.89 			$	3.90 		
							
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING		497,226,867 			495,306,238 			493,758,277 		

	
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	4.42 			$	3.88 			$	3.90 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	
125

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
Net Income		$	2,196.7 			$	1,919.8 			$	1,931.3 		
							
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES							
Cash Flow Hedges, Net of Tax of $1.8, $(21.1) and $3.9 in 2020, 2019 and 2018, Respectively		6.9 			(79.4)			14.6 		
	
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(1.9), $(1.5) and $(1.4) in 2020, 2019 and 2018, Respectively		(7.0)			(5.6)			(5.3)		
Pension and OPEB Funded Status, Net of Tax of $16.7, $15.3 and $(8.8) in 2020, 2019 and 2018, Respectively		62.7 			57.7 			(33.0)		
							
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		62.6 			(27.3)			(23.7)		
							
TOTAL COMPREHENSIVE INCOME		2,259.3 			1,892.5 			1,907.6 		
							
Total Comprehensive Income (Loss) Attributable To Noncontrolling Interests		(3.4)			(1.3)			7.5 		
							
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	2,262.7 			$	1,893.8 			$	1,900.1 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	
126

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

	AEP Common Shareholders					
	Common Stock						Accumulated
Other
Comprehensive
Income (Loss)					
	Shares		Amount		Paid-in
Capital		Retained
Earnings				Noncontrolling
Interests		Total	
TOTAL EQUITY – DECEMBER 31, 2017	512.2 			$	3,329.4 			$	6,398.7 			$	8,626.7 			$	(67.8)			$	26.6 			$	18,313.6 		
														
Issuance of Common Stock	1.3 			8.0 			65.6 									73.6 		
Common Stock Dividends							(1,251.1)		(a)			(4.4)			(1,255.5)		
Other Changes in Equity					21.8 							1.3 			23.1 		
ASU 2018-02 Adoption							14.0 			(17.0)					(3.0)		
ASU 2016-01 Adoption							11.9 			(11.9)					— 		
Net Income							1,923.8 					7.5 			1,931.3 		
Other Comprehensive Loss									(23.7)					(23.7)		
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	0.9 			6.0 			59.3 									65.3 		
Common Stock Dividends							(1,345.5)		(a)			(4.5)			(1,350.0)		
Other Changes in Equity					(9.8)		(b)					2.2 			(7.6)		
Acquisition of Sempra Renewables LLC											134.8 			134.8 		
Acquisition of Santa Rita East											118.8 			118.8 		
Net Income (Loss)							1,921.1 					(1.3)			1,919.8 		
Other Comprehensive Loss									(27.3)					(27.3)		
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	2.4 			15.9 			139.1 									155.0 		
Common Stock Dividends							(1,415.0)		(a)			(9.9)			(1,424.9)		
Other Changes in Equity					(85.8)		(c)					(0.4)			(86.2)		
ASU 2016-13 Adoption							1.8 							1.8 		
Acquisition of Incremental Interest
in Santa Rita East											(43.7)			(43.7)		
Net Income (Loss)							2,200.1 					(3.4)			2,196.7 		
Other Comprehensive Income									62.6 					62.6 		
TOTAL EQUITY – DECEMBER 31, 2020	516.8 			$	3,359.3 			$	6,588.9 			$	10,687.8 			$	(85.1)			$	223.6 			$	20,774.5 		

(a)    Cash dividends declared per AEP common share were $2.84, $2.71 and $2.53 for the years ended December 31, 2020, 2019 and 2018, respectively.
(b)    Includes $(62) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Note 14 for additional information.
(c)    Includes $(121) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Note 14 for additional information.

See Notes to Financial Statements of Registrants beginning on page 229.	

127

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2020 and 2019
(in millions)

		December 31,	
		2020		2019	
CURRENT ASSETS					
Cash and Cash Equivalents		$	392.7 			$	246.8 		
Restricted Cash
(December 31, 2020 and 2019 Amounts Include $45.6 and $185.8, Respectively, Related to Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Santa Rita East)		45.6 			185.8 		
Other Temporary Investments
(December 31, 2020 and 2019 Amounts Include $194.6 and $187.8, Respectively, Related to EIS and Transource Energy)		200.8 			202.7 		
Accounts Receivable:					
Customers		613.6 			625.3 		
Accrued Unbilled Revenues		248.7 			222.4 		
Pledged Accounts Receivable – AEP Credit		1,018.4 			873.9 		
Miscellaneous		33.1 			27.2 		
Allowance for Uncollectible Accounts		(71.1)			(43.7)		
Total Accounts Receivable		1,842.7 			1,705.1 		
Fuel		629.4 			528.5 		
Materials and Supplies		680.6 			640.7 		
Risk Management Assets		94.7 			172.8 		
Accrued Tax Benefits		185.3 			85.8 		
Regulatory Asset for Under-Recovered Fuel Costs		90.7 			92.9 		
Margin Deposits		62.0 			60.4 		
	
Prepayments and Other Current Assets		127.0 			156.3 		
TOTAL CURRENT ASSETS		4,351.5 			4,077.8 		
					
PROPERTY, PLANT AND EQUIPMENT					
Electric:					
Generation		23,133.9 			22,762.4 		
Transmission		27,886.7 			24,808.6 		
Distribution		23,972.1 			22,443.4 		
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)		5,294.6 			4,811.5 		
Construction Work in Progress		4,025.7 			4,319.8 		
Total Property, Plant and Equipment		84,313.0 			79,145.7 		
Accumulated Depreciation and Amortization		20,411.4 			19,007.6 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		63,901.6 			60,138.1 		
					
OTHER NONCURRENT ASSETS					
Regulatory Assets		3,527.0 			3,158.8 		
Securitized Assets		657.0 			858.1 		
Spent Nuclear Fuel and Decommissioning Trusts		3,306.7 			2,975.7 		
Goodwill		52.5 			52.5 		
Long-term Risk Management Assets		242.2 			266.6 		
Operating Lease Assets		866.4 			957.4 		
Deferred Charges and Other Noncurrent Assets		3,852.3 			3,407.3 		
TOTAL OTHER NONCURRENT ASSETS		12,504.1 			11,676.4 		
					
TOTAL ASSETS		$	80,757.2 			$	75,892.3 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	
128

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2020 and 2019
(dollars in millions)

							December 31,	
							2020		2019	
CURRENT LIABILITIES					
Accounts Payable							$	1,709.7 			$	2,085.8 		
Short-term Debt:										
Securitized Debt for Receivables – AEP Credit							592.0 			710.0 		
Other Short-term Debt							1,887.3 			2,128.3 		
Total Short-term Debt							2,479.3 			2,838.3 		
Long-term Debt Due Within One Year
(December 31, 2020 and 2019 Amounts Include $198.3 and $565.1, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)			2,086.1 			1,598.7 		
Risk Management Liabilities							78.8 			114.3 		
Customer Deposits							335.6 			366.1 		
Accrued Taxes							1,476.4 			1,357.8 		
Accrued Interest							267.6 			243.6 		
Obligations Under Operating Leases							241.3 			234.1 		
Regulatory Liability for Over-Recovered Fuel Costs							52.6 			86.6 		
	
Other Current Liabilities							1,199.3 			1,373.8 		
TOTAL CURRENT LIABILITIES							9,926.7 			10,299.1 		
										
NONCURRENT LIABILITIES					
Long-term Debt
(December 31, 2020 and 2019 Amounts Include $950.1 and $907, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)			28,986.4 			25,126.8 		
Long-term Risk Management Liabilities							232.8 			261.8 		
Deferred Income Taxes							8,240.9 			7,588.2 		
Regulatory Liabilities and Deferred Investment Tax Credits					8,378.7 			8,457.6 		
Asset Retirement Obligations							2,469.2 			2,216.6 		
Employee Benefits and Pension Obligations							336.4 			466.0 		
Obligations Under Operating Leases							638.4 			734.6 		
Deferred Credits and Other Noncurrent Liabilities							728.0 			719.8 		
TOTAL NONCURRENT LIABILITIES							50,010.8 			45,571.4 		
										
TOTAL LIABILITIES							59,937.5 			55,870.5 		
										
Rate Matters (Note 4)										
Commitments and Contingencies (Note 6)										
										
MEZZANINE EQUITY					
Redeemable Noncontrolling Interest							— 			65.7 		
Contingently Redeemable Performance Share Awards							45.2 			42.9 		
TOTAL MEZZANINE EQUITY							45.2 			108.6 		
										
EQUITY					
Common Stock – Par Value – $6.50 Per Share:										
		2020		2019						
Shares Authorized		600,000,000		600,000,000						
Shares Issued		516,808,354		514,373,631						
(20,204,160 Shares were Held in Treasury as of December 31, 2020 and 2019, Respectively)			3,359.3 			3,343.4 		
Paid-in Capital							6,588.9 			6,535.6 		
Retained Earnings							10,687.8 			9,900.9 		
Accumulated Other Comprehensive Income (Loss)							(85.1)			(147.7)		
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			20,550.9 			19,632.2 		
										
Noncontrolling Interests							223.6 			281.0 		
										
TOTAL EQUITY							20,774.5 			19,913.2 		
										
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY		$	80,757.2 			$	75,892.3 		
										
See Notes to Financial Statements of Registrants beginning on page 229.	

129

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
OPERATING ACTIVITIES							
Net Income		$	2,196.7 			$	1,919.8 			$	1,931.3 		

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:							
Depreciation and Amortization		2,682.8 			2,514.5 			2,286.6 		
Rockport Plant, Unit 2 Operating Lease Amortization		136.5 			136.5 			— 		
Deferred Income Taxes		196.1 			(17.8)			104.3 		
	
Asset Impairments and Other Related Charges		— 			156.4 			70.6 		
	
Allowance for Equity Funds Used During Construction		(148.1)			(168.4)			(132.5)		
Mark-to-Market of Risk Management Contracts		66.5 			(29.2)			(66.4)		
Amortization of Nuclear Fuel		87.5 			89.1 			113.8 		
Pension and Postemployment Benefit Reserves		(8.5)			(24.6)			(42.8)		
Pension Contributions to Qualified Plan Trust		(110.3)			— 			— 		
Property Taxes		(43.3)			(73.8)			(59.1)		
Deferred Fuel Over/Under-Recovery, Net		(31.8)			85.2 			189.7 		

	
	
Change in Regulatory Assets		(337.9)			49.5 			354.1 		
Change in Other Noncurrent Assets		(142.5)			(112.8)			(172.1)		
Change in Other Noncurrent Liabilities		(54.5)			(116.1)			129.0 		
Changes in Certain Components of Working Capital:							
Accounts Receivable, Net		(129.3)			247.8 			145.9 		
Fuel, Materials and Supplies		(142.9)			(248.2)			20.7 		
Accounts Payable		(35.3)			5.8 			36.6 		
Accrued Taxes, Net		20.1 			138.9 			153.2 		
Rockport Plant, Unit 2 Operating Lease Payments		(147.7)			(147.7)			— 		
Other Current Assets		34.3 			70.7 			10.5 		
Other Current Liabilities		(255.5)			(205.5)			149.8 		
Net Cash Flows from Operating Activities		3,832.9 			4,270.1 			5,223.2 		
							
INVESTING ACTIVITIES							
Construction Expenditures		(6,246.3)			(6,051.4)			(6,310.9)		
	
Purchases of Investment Securities		(1,678.8)			(1,576.0)			(2,067.8)		
Sales of Investment Securities		1,644.3 			1,494.2 			2,010.0 		
Acquisitions of Nuclear Fuel		(69.7)			(92.3)			(46.1)		
Acquisition of Sempra Renewables LLC and Santa Rita East, Net of Cash and Restricted Cash Acquired		— 			(918.4)			— 		

Other Investing Activities		116.6 			(0.6)			61.2 		
Net Cash Flows Used for Investing Activities		(6,233.9)			(7,144.5)			(6,353.6)		
							
FINANCING ACTIVITIES							
Issuance of Common Stock		155.0 			65.3 			73.6 		
Issuance of Long-term Debt		5,626.1 			4,536.6 			4,945.7 		
Issuance of Short-term Debt with Original Maturities Greater Than 90 Days		1,396.5 			— 			205.6 		
Change in Short-term Debt with Original Maturities Less Than 90 Day, Net		(448.4)			928.3 			271.4 		
Retirement of Long-term Debt		(1,339.8)			(1,220.8)			(2,782.0)		
Redemption of Short-term Debt with Original Maturities Greater Than 90 Days		(1,307.1)			— 			(205.6)		

Principal Payments for Finance Lease Obligations		(61.7)			(70.7)			(65.1)		
Dividends Paid on Common Stock		(1,424.9)			(1,350.0)			(1,255.5)		
Redemption of Noncontrolling Interests		(100.2)			— 			— 		
Other Financing Activities		(88.8)			(25.8)			(26.2)		
Net Cash Flows from Financing Activities		2,406.7 			2,862.9 			1,161.9 		

	

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash		5.7 			(11.5)			31.5 		
Cash, Cash Equivalents and Restricted Cash at Beginning of Period		432.6 			444.1 			412.6 		
Cash, Cash Equivalents and Restricted Cash at End of Period		$	438.3 			$	432.6 			$	444.1 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	
130

AEP TEXAS INC.
AND SUBSIDIARIES

131

AEP TEXAS INC. AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

COMPANY OVERVIEW

AEP Texas was formed by the merger of TCC and TNC into AEP Utilities on December 31, 2016. The merging parties consolidated the majority of their rate structures following the completion of their 2019 base rate case. See Note 4 - Rate Matters for additional information related to the 2019 base rate case. Following the merger, AEP Utilities changed its name to AEP Texas.

AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,068,000 retail customers through REPs in west, central and southern Texas. Among the principal industries served by AEP Texas are petroleum and coal products manufacturing, chemical manufacturing, oil and gas extraction, pipeline transportation and support activities for mining. The territory served by AEP Texas also includes several military installations and correctional facilities.  AEP Texas is a member of ERCOT.  Under Texas Restructuring Legislation, AEP Texas’ utility predecessors, TCC and TNC, exited the generation business and ceased serving retail load. However, AEP Texas continued as part owner in the Oklaunion Power Station operated by PSO until the Oklaunion Power Station was retired in September 2020 and subsequently sold to a nonaffiliated third-party in October 2020. See “Oklaunion Power Station” section of Note 7 for additional information about the sale.

AEP Texas consolidates AEP Texas North Generation Company, LLC, AEP Texas Central Transition Funding II LLC, AEP Texas Central Transition Funding III LLC and AEP Texas Restoration Funding LLC, its wholly-owned subsidiaries. The AEP Texas Central Transition Funding II LLC securitization bonds matured in July 2020.
132

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales	
						
	Years Ended December 31,	
	2020		2019		2018	
	(in millions of KWhs)	
Retail:						
Residential	12,163 			11,996 			12,101 		
Commercial	10,065 			10,419 			10,220 		
Industrial	9,085 			8,882 			9,053 		
Miscellaneous	636 			665 			646 		
Total Retail	31,949 			31,962 			32,020 		

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	
						
	Years Ended December 31,	
	2020		2019		2018	
	(in degree days)	
Actual – Heating (a)	189 			301 			354 		
Normal – Heating (b)	313 			322 			325 		
						
Actual – Cooling (c)	2,846 			2,989 			2,861 		
Normal – Cooling (b)	2,711 			2,699 			2,688 		

(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.

133

2020 Compared to 2019

Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Net Income
(in millions)

Year Ended December 31, 2019		$	178.3 		
			
Changes in Gross Margin:			
Retail Margins		34.2 		
Margins from Off-system Sales		(52.2)		
Transmission Revenues		21.6 		
Other Revenues		(76.6)		
Total Change in Gross Margin		(73.0)		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		81.4 		
Asset Impairments and Other Related Charges		32.5 		
Depreciation and Amortization		92.5 		
Taxes Other Than Income Taxes		4.2 		
Interest Income		(2.0)		
Allowance for Equity Funds Used During Construction		4.2 		
Non-Service Cost Components of Net Periodic Benefit Cost		(0.1)		
Interest Expense		(34.6)		
Total Change in Expenses and Other		178.1 		
			
Income Tax Expense		(42.4)		

Year Ended December 31, 2020		$	241.0 		

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

•Retail Margins increased $34 million primarily due to the following:
•A $30 million increase due to a provision for refund recorded in December 2019 as part of the most recent base rate case.
•A $19 million increase in weather-normalized margins primarily driven by the residential class and partially offset by a decrease in the industrial and commercial classes.
•A $16 million increase from interim rate increases driven by increased distribution investment.
•A $13 million increase due to new base rates implemented in June 2020.
•A $12 million increase from interim rate increases driven by increased transmission investment.
•A $5 million increase due to the change in the recording of merger savings as authorized by the PUCT in the most recent base rate case.
These increases were partially offset by:
•A $38 million decrease due to refunds of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was partially offset in Income Tax Expense below.
•A $17 million decrease in weather-related usage primarily due to a 5% decrease in cooling degree days and a 37% decrease in heating degree days.
•A $6 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
•Margins from Off-system Sales decreased $52 million due to lower Oklaunion Power Station PPA revenues. This decrease was partially offset in Other Operation and Maintenance expenses below.

134

•Transmission Revenues increased $22 million primarily due to the following:
•A $48 million increase from interim rate increases driven by increased transmission investment.
This increase was partially offset by:
•A $14 million decrease due to a one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This decrease was offset in Income Tax Expense below.
•An $11 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 $77 million primarily due to the following:
•A $96 million decrease related to 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 $18 million increase in revenues due to the amortization of a provision for refund recorded in December 2019 as part of the most recent base rate case. This increase was offset in Retail Margins and Transmission Revenues above.

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

•Other Operation and Maintenance expenses decreased $81 million primarily due to the following:
•A $67 million decrease due to prior year partial amortization of the AEP Texas Storm Restoration Securitization regulatory asset as a result of the AEP Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This decrease was offset in Income Tax Expense below.
•A $17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins from Off-system Sales above.
•A $6 million decrease due to a charitable contribution to the AEP Foundation in 2019.
These decreases were partially offset by:
•A $17 million increase in transmission expenses. This increase was partially offset in Gross Margin above.
•Asset Impairments and Other Related Charges decreased $33 million due to prior year regulatory disallowances in the 2019 Texas Base Rate Case.
•Depreciation and Amortization expenses decreased $93 million primarily due to the following:
•An $87 million decrease in securitization amortizations primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above and in Interest Expense below.
•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.
•Taxes Other Than Income Taxes decreased $4 million primarily due to lower property taxes.
•Allowance for Equity Funds Used During Construction increased $4 million primarily 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 $35 million primarily due to the following:
•A $22 million increase due to the prior year deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.
•A $19 million increase due to higher long-term debt balances.
•An $8 million increase due to a decrease in the debt component of AFUDC.
These increases were partially offset by:
•An $8 million decrease in expense related to securitization assets. This decrease was offset in Other Revenues and Depreciation and Amortization expenses above.
•A $5 million decrease due to lower short-term debt balances.
135

•Income Tax Expense increased $42 million primarily due to an increase in pretax book income and the prior year amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in 2019. This increase is partially offset by a decrease in state tax expense. The amortization of Excess ADIT was partially offset in Gross Margins and Other Operation and Maintenance expenses above.
136

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
AEP Texas Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of AEP Texas Inc. and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of income, of comprehensive income (loss), of changes in common shareholder's equity and of cash flows for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.

Change in Accounting Principle

As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that
our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
137

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, whether influenced by issuance of regulatory commission orders, passage of new legislation, or changes in the regulatory environment. As of December 31, 2020, there were $266.8 million of deferred costs included in regulatory assets, $32.9 million of which were pending final regulatory approval, and $1,270.8 million of regulatory
liabilities awaiting potential refund or future rate reduction, ($5.7) million of which were pending final regulatory determination.

The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and applying guidance contained in rate orders and other relevant evidence; which in turn led to significant audit effort and a high degree of auditor subjectivity in performing procedures and in evaluating audit evidence relating to management’s judgments about the probability of recovery of regulatory assets and refund of regulatory liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s assessment of regulatory proceedings, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, including those subject to pending rate cases, also involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, and application of regulatory precedents.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

We have served as the Company's auditor since 2017.
138

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of AEP Texas Inc. and Subsidiaries (AEP Texas) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  AEP Texas’ internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of AEP Texas’ internal control over financial reporting as of December 31, 2020.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013).  Based on management’s assessment, management concluded AEP Texas’ internal control over financial reporting was effective as of December 31, 2020.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, AEP Texas’ registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit AEP Texas to provide only management’s report in this annual report.
139

AEP TEXAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
 		2020		2019		2018	
REVENUES		 		 			
Electric Transmission and Distribution		$	1,524.9 			$	1,545.9 			$	1,486.3 		
Sales to AEP Affiliates		90.8 			160.5 			105.2 		
Other Revenues		3.2 			2.9 			3.8 		
TOTAL REVENUES		1,618.9 			1,709.3 			1,595.3 		
 							
EXPENSES		 		 		 	
Fuel and Other Consumables Used for Electric Generation		13.7 			31.1 			38.5 		
Other Operation		488.9 			492.0 			488.9 		
Maintenance		80.5 			158.8 			89.4 		
Asset Impairments and Other Related Charges		— 			32.5 			— 		
Depreciation and Amortization		529.8 			622.3 			499.6 		
Taxes Other Than Income Taxes		136.4 			140.6 			132.6 		
TOTAL EXPENSES		1,249.3 			1,477.3 			1,249.0 		
 							
OPERATING INCOME		369.6 			232.0 			346.3 		
 							
Other Income (Expense):		 		 		 	
Interest Income		1.4 			3.4 			0.8 		
	
Allowance for Equity Funds Used During Construction		19.4 			15.2 			20.0 		
	
Non-Service Cost Components of Net Periodic Benefit Cost		11.2 			11.3 			12.3 		
Interest Expense		(171.8)			(137.2)			(147.3)		
 							
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)		229.8 			124.7 			232.1 		
 							
Income Tax Expense (Benefit)		(11.2)			(53.6)			20.8 		
							
NET INCOME		$	241.0 			$	178.3 			$	211.3 		
							
The common stock of AEP Texas is wholly-owned by Parent.	
							
See Notes to Financial Statements of Registrants beginning on page 229.	

140

AEP TEXAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

 	 	Years Ended December 31,	
		2020		2019		2018	
Net Income		$	241.0 			$	178.3 			$	211.3 		
 							
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES		 		 		 	
Cash Flow Hedges, Net of Tax of $0.3, $0.3 and $0.3 in 2020, 2019 and 2018, Respectively		1.1 			1.0 			1.0 		
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0, $0 and $0.1 in 2020, 2019 and 2018, Respectively		0.2 			0.2 			0.2 		
Pension and OPEB Funded Status, Net of Tax of $0.7, $0.3 and $(0.3) in 2020, 2019 and 2018, Respectively		2.6 			1.1 			(1.0)		
							
TOTAL OTHER COMPREHENSIVE INCOME		3.9 			2.3 			0.2 		
 							
TOTAL COMPREHENSIVE INCOME		$	244.9 			$	180.6 			$	211.5 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	

141

AEP TEXAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017		$	1,057.9 			$	1,124.6 			$	(12.6)			$	2,169.9 		
									
Capital Contribution from Parent		200.0 							200.0 		
	
ASU 2018-02 Adoption				1.8 			(2.7)			(0.9)		
Net Income				211.3 					211.3 		
Other Comprehensive Income						0.2 			0.2 		
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				178.3 					178.3 		
Other Comprehensive Income						2.3 			2.3 		
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019		1,457.9 			1,516.0 			(12.8)			2,961.1 		

	
Net Income				241.0 					241.0 		
Other Comprehensive Income						3.9 			3.9 		
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020		$	1,457.9 			$	1,757.0 			$	(8.9)			$	3,206.0 		
									
See Notes to Financial Statements of Registrants beginning on page 229.	

142

AEP TEXAS INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2020 and 2019
(in millions)

		December 31,	
 		2020		2019	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	0.1 			$	3.1 		
Restricted Cash
(December 31, 2020 and 2019 Amounts Include $28.7 and $154.7, Respectively, Related to Transition Funding and Restoration Funding)		28.7 			154.7 		
Advances to Affiliates		7.1 			207.2 		
Accounts Receivable:		 		 	
Customers		112.8 			116.0 		
Affiliated Companies		5.1 			10.1 		
Accrued Unbilled Revenues		65.8 			68.8 		
Miscellaneous		— 			0.3 		
Allowance for Uncollectible Accounts		(0.1)			(1.8)		
Total Accounts Receivable		183.6 			193.4 		
Fuel		— 			5.9 		
Materials and Supplies		70.0 			56.7 		
	
Accrued Tax Benefits		16.8 			66.1 		
Prepayments and Other Current Assets		4.6 			5.8 		
TOTAL CURRENT ASSETS		310.9 			692.9 		
 					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Generation		— 			351.7 		
Transmission		5,279.6 			4,466.5 		
Distribution		4,580.8 			4,215.2 		
Other Property, Plant and Equipment		868.4 			805.9 		
Construction Work in Progress		614.1 			763.9 		
Total Property, Plant and Equipment		11,342.9 			10,603.2 		
Accumulated Depreciation and Amortization		1,529.3 			1,758.1 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		9,813.6 			8,845.1 		
 					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		266.8 			280.6 		
Securitized Assets
(December 31, 2020 and 2019 Amounts Include $446.8 and $621.2, Respectively, Related to Transition Funding and Restoration Funding)		446.8 			623.4 		
	
Deferred Charges and Other Noncurrent Assets		192.1 			147.1 		
TOTAL OTHER NONCURRENT ASSETS		905.7 			1,051.1 		
					
TOTAL ASSETS		$	11,030.2 			$	10,589.1 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	

143

AEP TEXAS INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
December 31, 2020 and 2019
(in millions)

		December 31,	
 	 	2020	 	2019	
CURRENT LIABILITIES		 		 	
Advances from Affiliates		$	67.1 			$	— 		
Accounts Payable:					
General		231.7 			256.8 		
Affiliated Companies		44.0 			35.6 		
Long-term Debt Due Within One Year – Nonaffiliated
(December 31, 2020 and 2019 Amounts Include $88.7 and $281.4, Respectively, Related to Transition Funding and Restoration Funding)		88.7 			392.1 		

Accrued Taxes		78.3 			84.9 		
Accrued Interest
(December 31, 2020 and 2019 Amounts Include $2.5 and $7.5, Respectively, Related to Transition Funding and Restoration Funding)		43.9 			35.7 		
Oklaunion Purchase Power Agreement		— 			22.1 		
Obligations Under Operating Leases		14.5 			12.0 		
Provision for Refund		20.1 			64.7 		
Other Current Liabilities		88.5 			123.3 		
TOTAL CURRENT LIABILITIES		676.8 			1,027.2 		
					
NONCURRENT LIABILITIES		 			
Long-term Debt – Nonaffiliated
(December 31, 2020 and 2019 Amounts Include $403.9 and $495.4, Respectively, Related to Transition Funding and Restoration Funding)		4,731.7 			4,166.3 		
	
Deferred Income Taxes		1,016.7 			965.4 		
Regulatory Liabilities and Deferred Investment Tax Credits		1,270.8 			1,316.9 		
	
Obligations Under Operating Leases		71.0 			71.1 		
Deferred Credits and Other Noncurrent Liabilities		57.2 			81.1 		
TOTAL NONCURRENT LIABILITIES		7,147.4 			6,600.8 		
					
TOTAL LIABILITIES		7,824.2 			7,628.0 		
					
Rate Matters (Note 4)					
Commitments and Contingencies (Note 6)	 				
 	 				
COMMON SHAREHOLDER’S EQUITY	 	 		 	

	
Paid-in Capital	 	1,457.9 			1,457.9 		
Retained Earnings	 	1,757.0 			1,516.0 		
Accumulated Other Comprehensive Income (Loss)		(8.9)			(12.8)		
TOTAL COMMON SHAREHOLDER’S EQUITY	 	3,206.0 			2,961.1 		
 	 				
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY	 	$	11,030.2 			$	10,589.1 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	

144

AEP TEXAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

 		Years Ended December 31,	
 	 	2020		2019		2018	
OPERATING ACTIVITIES	 	 		 			
Net Income	 	$	241.0 			$	178.3 			$	211.3 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:	 						
Depreciation and Amortization	 	529.8 			622.3 			499.6 		
Deferred Income Taxes	 	(15.2)			(23.5)			(16.5)		
Asset Impairments and Other Related Charges		— 			32.5 			— 		
Allowance for Equity Funds Used During Construction		(19.4)			(15.2)			(20.0)		
Mark-to-Market of Risk Management Contracts	 	— 			(0.2)			0.7 		
Pension Contributions to Qualified Plan Trust		(11.3)			— 			— 		

Change in Other Noncurrent Assets	 	(74.0)			9.3 			(60.3)		
Change in Other Noncurrent Liabilities	 	(24.7)			11.3 			44.9 		
Changes in Certain Components of Working Capital:	 						
Accounts Receivable, Net	 	9.8 			3.5 			(2.9)		
Fuel, Materials and Supplies	 	(7.4)			(1.0)			(6.0)		
Accounts Payable	 	30.2 			7.5 			(20.3)		
	
Accrued Taxes, Net		42.7 			(11.8)			(5.6)		
	
Other Current Assets	 	0.8 			(0.4)			0.8 		
Other Current Liabilities	 	(88.1)			10.8 			26.2 		
Net Cash Flows from Operating Activities	 	614.2 			823.4 			651.9 		
	 						
INVESTING ACTIVITIES	 						
Construction Expenditures		(1,295.0)			(1,275.1)			(1,428.8)		
Change in Advances to Affiliates, Net	 	200.1 			(199.2)			103.9 		
	
Other Investing Activities		29.5 			2.1 			35.2 		
Net Cash Flows Used for Investing Activities	 	(1,065.4)			(1,472.2)			(1,289.7)		
	 						
FINANCING ACTIVITIES	 						
Capital Contribution from Parent		— 			200.0 			200.0 		
Issuance of Long-term Debt – Nonaffiliated		652.7 			1,070.4 			494.0 		
Change in Advances from Affiliates, Net	 	67.1 			(216.0)			216.0 		
Retirement of Long-term Debt – Nonaffiliated	 	(392.1)			(401.8)			(266.1)		
Principal Payments for Finance Lease Obligations	 	(6.3)			(5.1)			(4.7)		
	
Other Financing Activities		0.8 			(0.7)			1.2 		
Net Cash Flows from Financing Activities	 	322.2 			646.8 			640.4 		
							
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash		(129.0)			(2.0)			2.6 		
Cash, Cash Equivalents and Restricted Cash at Beginning of Period		157.8 			159.8 			157.2 		
Cash, Cash Equivalents and Restricted Cash at End of Period		$	28.8 			$	157.8 			$	159.8 		
	 						
SUPPLEMENTARY INFORMATION	 						
Cash Paid for Interest, Net of Capitalized Amounts	 	$	153.2 			$	148.6 			$	145.9 		
Net Cash Paid (Received) for Income Taxes	 	(42.9)			(11.0)			7.9 		
Noncash Acquisitions Under Finance Leases	 	5.6 			11.4 			10.6 		
Construction Expenditures Included in Current Liabilities as of December 31,	 	177.8 			225.5 			243.1 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	
145

AEP TRANSMISSION COMPANY, LLC
AND SUBSIDIARIES
146

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

COMPANY OVERVIEW

AEPTCo is a holding company for seven FERC regulated transmission-only electric utilities. AEPTCo is an indirect wholly-owned subsidiary of American Electric Power Company, Inc. (AEP).

AEPTCo’s seven wholly-owned public utility companies are (collectively referred to herein as the State Transcos):
•AEP Appalachian Transmission Company, Inc. (APTCo)
•AEP Indiana Michigan Transmission Company, Inc. (IMTCo)
•AEP Kentucky Transmission Company, Inc. (KTCo)
•AEP Ohio Transmission Company, Inc. (OHTCo)
•AEP West Virginia Transmission Company, Inc. (WVTCo)
•AEP Oklahoma Transmission Company, Inc. (OKTCo)
•AEP Southwestern Transmission Company, Inc. (SWTCo)

AEPTCo’s business activities are the development, construction and operation of transmission facilities through investments in seven wholly-owned FERC-regulated transmission only electric subsidiaries.
147

RESULTS OF OPERATIONS

Summary of Investment in Transmission Assets for AEPTCo

		As of December 31,	
		2020		2019		2018	
		(in millions)	
Plant In Service		$	9,923.0 			$	8,407.5 			$	6,689.8 		
CWIP		1,422.6 			1,485.7 			1,578.3 		
Accumulated Depreciation		572.8 			402.3 			271.9 		
Total Transmission Property, Net		$	10,772.8 			$	9,490.9 			$	7,996.2 		

2020 Compared to 2019

Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Net Income
(in millions)

Year Ended December 31, 2019		$	439.7 		
			
Changes in Transmission Revenues:			
Transmission Revenues		124.3 		
Total Change in Transmission Revenues		124.3 		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		(0.7)		
Depreciation and Amortization		(73.0)		
Taxes Other Than Income Taxes		(36.3)		
Interest Income - Affiliated		(0.6)		
Allowance for Equity Funds Used During Construction		(10.3)		
Interest Expense		(30.4)		
Total Change in Expenses and Other		(151.3)		
			
Income Tax Expense		10.7 		

Year Ended December 31, 2020		$	423.4 		

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

•Transmission Revenues increased $124 million primarily due to the following:
•A $205 million increase due to continued investment in transmission assets.
This increase was partially offset by the following:
•A $65 million decrease as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across affiliated load-serving entities.
•A $17 million decrease as a result of the nonaffiliated annual transmission formula rate true-up.

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

•Depreciation and Amortization expenses increased $73 million primarily due to a higher depreciable base and an increase in depreciation rates as a result of regulatory orders in 2020 in Indiana, Virginia and Michigan.
•Taxes Other Than Income Taxes increased $36 million primarily due to higher property taxes as a result of increased transmission investment.

148

•Allowance for Equity Funds Used During Construction decreased $10 million primarily due to the following:
•A $13 million decrease due to lower CWIP.
•A $12 million decrease driven by the favorable impact of a FERC settlement agreement recorded in 2019.
These decreases were partially offset by:
•A $13 million increase driven by FERC audit findings recorded in 2019.
•Interest Expense increased $30 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $11 million primarily due to lower pretax book income, a decrease in state tax expense and an increase in Excess ADIT amortization.
149

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Member of
AEP Transmission Company, LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of AEP Transmission Company, LLC and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of income, of changes in member's equity and of cash flows for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

150

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, whether influenced by issuance of regulatory commission orders, passage of new legislation, or changes in the regulatory environment. As of December 31, 2020, there were $15.1 million of deferred costs included in regulatory assets and $581.8 million of regulatory liabilities awaiting potential refund or future rate reduction.

The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and applying guidance contained in rate orders and other relevant evidence; which in turn led to significant audit effort and a high degree of auditor subjectivity in performing procedures and in evaluating audit evidence relating to management’s judgments about the probability of recovery of regulatory assets and refund of regulatory liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s assessment of regulatory proceedings, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, including those subject to pending rate cases, also involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, and application of regulatory precedents.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

We have served as the Company's auditor since 2017.
151

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of AEP Transmission Company, LLC and Subsidiaries (AEPTCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  AEPTCo’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of AEPTCo’s internal control over financial reporting as of December 31, 2020.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013).  Based on management’s assessment, management concluded AEPTCo’s internal control over financial reporting was effective as of December 31, 2020.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, AEPTCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit AEPTCo to provide only management’s report in this annual report.
152

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
REVENUES							
Transmission Revenues		$	248.8 			$	214.6 			$	177.0 		
Sales to AEP Affiliates		896.3 			806.7 			598.9 		
Other Revenues		0.6 			0.1 			0.2 		
TOTAL REVENUES		1,145.7 			1,021.4 			776.1 		
							
EXPENSES							
Other Operation		99.8 			93.9 			83.8 		
Maintenance		10.2 			15.4 			10.5 		
Depreciation and Amortization		249.0 			176.0 			133.9 		
Taxes Other Than Income Taxes		205.2 			168.9 			137.8 		
TOTAL EXPENSES		564.2 			454.2 			366.0 		
							
OPERATING INCOME		581.5 			567.2 			410.1 		
							
Other Income (Expense):							
Interest Income - Affiliated		2.4 			3.0 			2.5 		
Allowance for Equity Funds Used During Construction		74.0 			84.3 			70.6 		
Interest Expense		(127.8)			(97.4)			(83.2)		
							
INCOME BEFORE INCOME TAX EXPENSE		530.1 			557.1 			400.0 		
							
Income Tax Expense		106.7 			117.4 			84.1 		
							
NET INCOME		$	423.4 			$	439.7 			$	315.9 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	

153

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Paid-in
Capital		Retained
Earnings		Total Member’s Equity	
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2017		$	1,816.6 			$	773.3 			$	2,589.9 		
							
Capital Contribution from Member		664.0 					664.0 		
Net Income				315.9 			315.9 		
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2018		2,480.6 			1,089.2 			3,569.8 		

Net Income				439.7 			439.7 		
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2019		2,480.6 			1,528.9 			4,009.5 		
							
Capital Contribution from Member		335.0 					335.0 		
Capital Distribution of Radial Assets to Member		(50.0)					(50.0)		
Dividends Paid to Member				(5.0)			(5.0)		
Net Income				423.4 			423.4 		
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2020		$	2,765.6 			$	1,947.3 			$	4,712.9 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	
154

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2020 and 2019
(in millions)

		December 31,	
		2020		2019	
CURRENT ASSETS					
Advances to Affiliates		$	109.1 			$	85.4 		
Accounts Receivable:					
Customers		22.9 			19.0 		
Affiliated Companies		81.2 			66.1 		
	
Total Accounts Receivable		104.1 			85.1 		
Materials and Supplies		8.5 			13.8 		
Accrued Tax Benefits		9.9 			9.3 		
Prepayments and Other Current Assets		4.2 			3.8 		
TOTAL CURRENT ASSETS		235.8 			197.4 		
					
TRANSMISSION PROPERTY					
Transmission Property		9,593.5 			8,137.9 		
Other Property, Plant and Equipment		329.5 			269.6 		
Construction Work in Progress		1,422.6 			1,485.7 		
Total Transmission Property		11,345.6 			9,893.2 		
Accumulated Depreciation and Amortization		572.8 			402.3 		
TOTAL TRANSMISSION PROPERTY – NET		10,772.8 			9,490.9 		
					
OTHER NONCURRENT ASSETS					
	
Regulatory Assets		15.1 			4.2 		
Deferred Property Taxes		220.1 			193.5 		
Deferred Charges and Other Noncurrent Assets		2.2 			4.8 		
TOTAL OTHER NONCURRENT ASSETS		237.4 			202.5 		
					
TOTAL ASSETS		$	11,246.0 			$	9,890.8 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	
155

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
December 31, 2020 and 2019

		December 31,	
		2020		2019	
		(in millions)	
CURRENT LIABILITIES					
Advances from Affiliates		$	156.7 			$	137.0 		
Accounts Payable:					
General		380.4 			493.4 		
Affiliated Companies		97.3 			71.2 		
Long-term Debt Due Within One Year – Nonaffiliated		50.0 			— 		
Accrued Taxes		418.1 			355.6 		
Accrued Interest		23.9 			19.2 		
Obligations Under Operating Leases		1.2 			2.1 		
Other Current Liabilities		9.9 			14.6 		
TOTAL CURRENT LIABILITIES		1,137.5 			1,093.1 		
					
NONCURRENT LIABILITIES					
Long-term Debt – Nonaffiliated		3,898.5 			3,427.3 		
Deferred Income Taxes		906.9 			817.8 		
Regulatory Liabilities		581.8 			540.9 		
Obligations Under Operating Leases		0.4 			1.9 		
Deferred Credits and Other Noncurrent Liabilities		8.0 			0.3 		
TOTAL NONCURRENT LIABILITIES		5,395.6 			4,788.2 		
					
TOTAL LIABILITIES		6,533.1 			5,881.3 		
					
Rate Matters (Note 4)					
Commitments and Contingencies (Note 6)					
					
MEMBER’S EQUITY					
Paid-in Capital		2,765.6 			2,480.6 		
Retained Earnings		1,947.3 			1,528.9 		
TOTAL MEMBER’S EQUITY		4,712.9 			4,009.5 		
					
TOTAL LIABILITIES AND MEMBER’S EQUITY		$	11,246.0 			$	9,890.8 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	
156

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
OPERATING ACTIVITIES							
Net Income		$	423.4 			$	439.7 			$	315.9 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:							
Depreciation and Amortization		249.0 			176.0 			133.9 		
Deferred Income Taxes		81.6 			91.3 			98.9 		
Allowance for Equity Funds Used During Construction		(74.0)			(84.3)			(70.6)		
Property Taxes		(26.6)			(35.6)			(32.9)		
	
Change in Other Noncurrent Assets		(8.2)			9.6 			14.6 		
Change in Other Noncurrent Liabilities		8.3 			(8.1)			17.4 		
Changes in Certain Components of Working Capital:							
Accounts Receivable, Net		(19.0)			(5.4)			36.7 		
Materials and Supplies		5.3 			5.2 			(5.4)		
Accounts Payable		77.8 			37.6 			(7.5)		
Accrued Taxes, Net		62.7 			90.8 			73.4 		
Accrued Interest		4.7 			3.3 			0.9 		
Other Current Assets		0.7 			(0.3)			(0.3)		
Other Current Liabilities		(14.5)			(11.2)			(26.4)		
Net Cash Flows from Operating Activities		771.2 			708.6 			548.6 		
							
INVESTING ACTIVITIES							
Construction Expenditures		(1,615.9)			(1,410.1)			(1,526.4)		
Change in Advances to Affiliates, Net		(23.7)			11.5 			49.4 		
Acquisitions of Assets		(6.0)			(9.4)			(37.4)		
	
Other Investing Activities		5.2 			4.8 			1.1 		
Net Cash Flows Used for Investing Activities		(1,640.4)			(1,403.2)			(1,513.3)		
							
FINANCING ACTIVITIES							
Capital Contributions from Member		335.0 			— 			664.0 		
Issuance of Long-term Debt – Nonaffiliated		519.5 			688.0 			321.0 		
Change in Advances from Affiliates, Net		19.7 			91.6 			29.7 		
Retirement of Long-term Debt – Nonaffiliated		— 			(85.0)			(50.0)		
Dividends Paid to Member		(5.0)			— 			— 		
	
Net Cash Flows from Financing Activities		869.2 			694.6 			964.7 		
							
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		$	119.7 			$	90.6 			$	80.2 		
Net Cash Paid (Received) for Income Taxes		22.9 			1.5 			(30.7)		
	
Construction Expenditures Included in Current Liabilities as of December 31,		311.9 			472.7 			345.0 		
Noncash Distribution of Radial Assets to Member		(50.0)			— 			— 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	
157

APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

158

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

COMPANY OVERVIEW

As a public utility, APCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 964,000 retail customers in its service territory in southwestern Virginia and southern West Virginia.  APCo consolidates Cedar Coal Company, Central Appalachian Coal Company, Southern Appalachian Coal Company and Appalachian Consumer Rate Relief Funding LLC, its wholly-owned subsidiaries.  APCo sells power at wholesale to municipalities.

To minimize the credit requirements and operating constraints when operating within PJM, participating AEP companies, including APCo, agreed to a netting of certain payment obligations incurred by the participating AEP companies against certain balances due to such AEP companies and to hold PJM harmless from actions that any one or more AEP companies may take with respect to PJM.

159

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales	
						
	Years Ended December 31,	
	2020		2019		2018	
	(in millions of KWhs)	
Retail:						
Residential	10,916 			11,253 			11,871 		
Commercial	5,887 			6,365 			6,581 		
Industrial	8,873 			9,546 			9,576 		
Miscellaneous	794 			857 			866 		
Total Retail	26,470 			28,021 			28,894 		
						
Wholesale	3,281 			3,085 			2,693 		
						
Total KWhs	29,751 			31,106 			31,587 		

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	
						
	Years Ended December 31,	
	2020		2019		2018	
	(in degree days)	
Actual – Heating (a)	1,764 			2,057 			2,400 		
Normal – Heating (b)	2,216 			2,224 			2,230 		
						
Actual – Cooling (c)	1,379 			1,597 			1,587 		
Normal – Cooling (b)	1,236 			1,221 			1,208 		

(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.

160

2020 Compared to 2019

Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Net Income
(in millions)

Year Ended December 31, 2019		$	306.3 		
			
Changes in Gross Margin:			
Retail Margins		(0.8)		
Margins from Off-system Sales		(3.7)		
Transmission Revenues		3.0 		
Other Revenues		(2.1)		
Total Change in Gross Margin		(3.6)		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		65.7 		
Asset Impairment and Other Related Charges - Coal Fired Generation		92.9 		
Re-Establishment of Regulatory Asset - Coal Fired Generation		49.0 		
Depreciation and Amortization		(40.7)		
Taxes Other Than Income Taxes		(4.0)		
Interest Income		(0.8)		
	
Allowance for Equity Funds Used During Construction		(2.0)		
Non-Service Cost Components of Net Periodic Benefit Cost		1.8 		
Interest Expense		(12.6)		
Total Change in Expenses and Other		149.3 		
			
Income Tax Expense		(82.3)		
			
Year Ended December 31, 2020		$	369.7 		

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 $1 million primarily due to the following:
•A $58 million decrease in weather-related usage primarily driven by a 14% decrease in heating degree days and a 14% decrease in cooling degree days.
•A $44 million decrease due to the cumulative impact of the implementation of APCo’s 2017 and 2019 generation and distribution depreciation studies as ordered in the Virginia triennial base rate case.
•A $19 million decrease in weather-normalized margins primarily in the commercial and industrial classes, partially offset in the residential class.
These decreases were partially offset by:
•A $33 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $26 million increase in deferred fuel primarily due to the timing of recoverable PJM expenses.
•A $16 million increase due to the WVPSC approval of the Mitchell Plant surcharge effective January 2020. Pursuant to the WVPSC approval of the surcharge, this increase was partially offset by the amortization of Excess ADIT not subject to normalization requirements in Income Tax Expense below.
•A $13 million increase due to rider revenues primarily in West Virginia. This increase was partially offset in other expense items below.
•A $12 million increase due to the impact of the 2019 WVPSC order which required APCo 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 West Virginia base rate increase implemented in March 2019. This increase was partially offset in Depreciation and Amortization expenses below.
•A $9 million increase due to an environmental expense deferral.
161

•Margins from Off-system Sales decreased $4 million due to weaker market prices for energy in RTOs which caused a decrease in sales volume and margins.
•Transmission Revenues increased $3 million primarily due to the following:
•A $12 million increase due to the implementation of updated depreciation rates as ordered in the 2017-2019 Virginia triennial base rate case. The impact of the revised depreciation rates will be reflected in the annual transmission formula rate true-up. This increase was offset in Depreciation Expense below.
•A $4 million increase from investment in transmission assets.
These increases were partially offset by:
•A $13 million decrease from the annual transmission formula rate true-up.

Expenses and Other and Income Tax Expense changed between years as follows:
 
•Other Operation and Maintenance expenses decreased $66 million primarily due to the following:
•A $24 million decrease in transmission expenses primarily due to the annual transmission formula rate true-up.
•A $24 million decrease as a result of prior year contributions to benefit low income West Virginia residential customers as a result of the West Virginia Tax Reform settlement. This decrease was offset in Income Tax Expense below.
•A $13 million decrease in storm-related expenses.
•A $9 million decrease in maintenance expense at various generation plants.
These decreases were partially offset by:
•A $9 million increase in expense due to the current year amortization of regulatory assets related to the 2017-2019 Virginia triennial review which authorized regulatory recovery of previously retired coal-fired generation assets.
•An $8 million increase in vegetation management services. This increase was offset in Retail Margin above.
•Asset Impairments and Other Related Charges - Coal Fired Generation decreased $93 million due to a pretax expense recorded in 2019 related to previously retired coal-fired generation assets.
•Re-Establishment of Regulatory Asset - Coal Fired Generation increased $49 million due to the 2017-2019 Virginia triennial review which authorized regulatory recovery of previously retired coal-fired generation assets.
•Depreciation and Amortization expenses increased $41 million primarily due to:
•A $35 million increase due to a higher depreciable base.
•A $17 million increase in West Virginia depreciation rates beginning in March 2019.
These increases were partially offset by:
•A $12 million decrease due to the cumulative impact of the implementation of APCo’s 2017 and 2019 depreciation studies as ordered in the Virginia triennial base rate case.
•Taxes Other Than Income Taxes increased $4 million primarily due to an increase in West Virginia business and occupational taxes.
•Interest Expense increased $13 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $82 million primarily due to an increase in pretax book income as well as a decrease in amortization of Excess ADIT not subject to normalization requirements. The decrease in Excess ADIT was partially offset in Gross Margin and Other Operation and Maintenance expenses above.
162

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Appalachian Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Appalachian Power Company and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of income, of comprehensive income (loss), of changes in common shareholder's equity and of cash flows for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.

Change in Accounting Principle

As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that
our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
163

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1, 4, and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, whether influenced by issuance of regulatory commission orders, passage of new legislation, or changes in the regulatory environment, which included a $49.0 million gain recorded for the year ended December 31, 2020 for the re-establishment of a regulatory asset related to previously retired coal fired generation assets as the result of the 2017-2019 Virginia triennial review. As of December 31, 2020, there were $691.6 million of deferred costs included in regulatory assets, $43.8 million of which were pending final regulatory approval, and $1,224.7 million of regulatory liabilities awaiting potential refund or future rate reduction.

The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and applying guidance contained in rate orders and other relevant evidence; which in turn led to significant audit effort and a high degree of auditor subjectivity in performing procedures and in evaluating audit evidence relating to management’s judgments about the probability of recovery of regulatory assets and refund of regulatory liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s assessment of regulatory proceedings, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, including those subject to pending rate cases, also involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, and application of regulatory precedents.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

We have served as the Company's auditor since 2017.
164

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Appalachian Power Company and Subsidiaries (APCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  APCo’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of APCo’s internal control over financial reporting as of December 31, 2020.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013).  Based on management’s assessment, management concluded APCo’s internal control over financial reporting was effective as of December 31, 2020.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, APCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit APCo to provide only management’s report in this annual report.
165

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
REVENUES							
Electric Generation, Transmission and Distribution		$	2,610.9 			$	2,708.2 			$	2,777.1 		
Sales to AEP Affiliates		174.7 			205.3 			181.4 		
Other Revenues		10.6 			11.2 			9.0 		
TOTAL REVENUES		2,796.2 			2,924.7 			2,967.5 		
							
EXPENSES							
Fuel and Other Consumables Used for Electric Generation		513.3 			607.5 			588.9 		
Purchased Electricity for Resale		360.3 			391.0 			503.5 		
	
Other Operation		530.5 			567.6 			511.6 		
Maintenance		226.8 			255.4 			316.9 		
Asset Impairments and Other Related Charges - Coal Fired Generation		— 			92.9 			— 		
Re-Establishment of Regulatory Asset - Coal Fired Generation		(49.0)			— 			— 		
Depreciation and Amortization		507.5 			466.8 			428.4 		
Taxes Other Than Income Taxes		150.2 			146.2 			134.7 		
TOTAL EXPENSES		2,239.6 			2,527.4 			2,484.0 		
							
OPERATING INCOME		556.6 			397.3 			483.5 		
							
Other Income (Expense):							
Interest Income		1.6 			2.4 			1.8 		
Carrying Costs Income		— 			— 			1.3 		
Allowance for Equity Funds Used During Construction		14.6 			16.6 			13.2 		
Non-Service Cost Components of Net Periodic Benefit Cost		18.8 			17.0 			17.9 		
Interest Expense		(217.6)			(205.0)			(194.8)		
							
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)		374.0 			228.3 			322.9 		
							
Income Tax Expense (Benefit)		4.3 			(78.0)			(44.9)		
							
NET INCOME		$	369.7 			$	306.3 			$	367.8 		
							
The common stock of APCo is wholly-owned by Parent.	
							
See Notes to Financial Statements of Registrants beginning on page 229.	
166

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2020, 2019 and 2018
 (in millions)

		Years Ended December 31,	
		2020		2019		2018	
Net Income		$	369.7 			$	306.3 			$	367.8 		
							
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES							
Cash Flow Hedges, Net of Tax of $(0.5), $(0.2) and $(0.2) in 2020, 2019 and 2018, Respectively		(1.7)			(0.9)			(0.9)		
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(1.0), $(0.7) and $(0.8) in 2020, 2019 and 2018, Respectively		(3.8)			(2.5)			(3.1)		
Pension and OPEB Funded Status, Net of Tax of $2.0, $3.6 and $(0.7) in 2020, 2019 and 2018, Respectively		7.7		13.4		(2.6)		
							
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		2.2 			10.0 			(6.6)		
							
TOTAL COMPREHENSIVE INCOME		$	371.9 			$	316.3 			$	361.2 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	
167

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

	Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	260.4 			$	1,828.7 			$	1,714.1 			$	1.3 			$	3,804.5 		
										
Common Stock Dividends					(160.0)					(160.0)		
ASU 2018-02 Adoption					0.1 			0.3 			0.4 		
Net Income					367.8 					367.8 		
Other Comprehensive Loss							(6.6)			(6.6)		
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018	260.4 			1,828.7 			1,922.0 			(5.0)			4,006.1 		
										
Common Stock Dividends					(150.0)					(150.0)		
Net Income					306.3 					306.3 		
Other Comprehensive Income							10.0 			10.0 		
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019	260.4 			1,828.7 			2,078.3 			5.0 			4,172.4 		
										
Common Stock Dividends					(200.0)					(200.0)		
Net Income					369.7 					369.7 		
Other Comprehensive Income							2.2 			2.2 		
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020	$	260.4 			$	1,828.7 			$	2,248.0 			$	7.2 			$	4,344.3 		
										
See Notes to Financial Statements of Registrants beginning on page 229.	
168

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2020 and 2019
(in millions)

		December 31,	
		2020		2019	
CURRENT ASSETS					
Cash and Cash Equivalents		$	5.8 			$	3.3 		
Restricted Cash for Securitized Funding		16.9 			23.5 		
Advances to Affiliates		21.4 			22.1 		
Accounts Receivable:					
Customers		142.8 			129.0 		
Affiliated Companies		64.3 			64.3 		
Accrued Unbilled Revenues		80.1 			59.7 		
Miscellaneous		0.3 			0.5 		
Allowance for Uncollectible Accounts		(3.1)			(2.6)		
Total Accounts Receivable		284.4 			250.9 		
Fuel		193.6 			149.7 		
Materials and Supplies		99.6 			105.2 		
Risk Management Assets		22.4 			39.4 		
	
Regulatory Asset for Under-Recovered Fuel Costs		5.3 			42.5 		
	
Prepayments and Other Current Assets		24.7 			64.0 		
TOTAL CURRENT ASSETS		674.1 			700.6 		
					
PROPERTY, PLANT AND EQUIPMENT					
Electric:					
Generation		6,633.7 			6,563.7 		
Transmission		3,900.5 			3,584.1 		
Distribution		4,464.3 			4,201.7 		
Other Property, Plant and Equipment		627.2 			571.3 		
Construction Work in Progress		484.6 			593.4 		
Total Property, Plant and Equipment		16,110.3 			15,514.2 		
Accumulated Depreciation and Amortization		4,716.2 			4,432.3 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		11,394.1 			11,081.9 		
					
OTHER NONCURRENT ASSETS					
Regulatory Assets		686.3 			457.2 		
Securitized Assets		210.1 			234.7 		
	
Employee Benefits and Pension Assets		150.1 			92.0 		
Operating Lease Assets		78.8 			78.5 		
Deferred Charges and Other Noncurrent Assets		121.7 			123.4 		
TOTAL OTHER NONCURRENT ASSETS		1,247.0 			985.8 		
					
TOTAL ASSETS		$	13,315.2 			$	12,768.3 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	
169

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
December 31, 2020 and 2019

		December 31,	
		2020		2019	
		(in millions)	
CURRENT LIABILITIES					
Advances from Affiliates		$	18.6 			$	236.7 		
Accounts Payable:					
General		212.0 			307.8 		
Affiliated Companies		97.1 			92.5 		
Long-term Debt Due Within One Year - Nonaffiliated		518.3 			215.6 		
	
Risk Management Liabilities		4.6 			1.9 		
Customer Deposits		77.8 			85.8 		
	
Accrued Taxes		109.9 			99.6 		
	
Obligations Under Operating Leases		14.9 			15.2 		
	
Other Current Liabilities		164.5 			170.9 		
TOTAL CURRENT LIABILITIES		1,217.7 			1,226.0 		
					
NONCURRENT LIABILITIES					
Long-term Debt – Nonaffiliated		4,315.8 			4,148.2 		

Deferred Income Taxes		1,749.9 			1,680.8 		
Regulatory Liabilities and Deferred Investment Tax Credits		1,224.7 			1,268.7 		
Asset Retirement Obligations		304.8 			102.1 		
Employee Benefits and Pension Obligations		44.0 			50.9 		
Obligations Under Operating Leases		64.4 			64.0 		
Deferred Credits and Other Noncurrent Liabilities		49.6 			55.2 		
TOTAL NONCURRENT LIABILITIES		7,753.2 			7,369.9 		
					
TOTAL LIABILITIES		8,970.9 			8,595.9 		
					
Rate Matters (Note 4)					
Commitments and Contingencies (Note 6)					
					
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		2,248.0 			2,078.3 		
Accumulated Other Comprehensive Income (Loss)		7.2 			5.0 		
TOTAL COMMON SHAREHOLDER’S EQUITY		4,344.3 			4,172.4 		
					
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY		$	13,315.2 			$	12,768.3 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	

170

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
OPERATING ACTIVITIES							
Net Income		$	369.7 			$	306.3 			$	367.8 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:							
Depreciation and Amortization		507.5 			466.8 			428.4 		
Deferred Income Taxes		(26.2)			(126.2)			(16.8)		
Asset Impairments and Other Related Charges - Coal Fired Generation		— 			92.9 			— 		

Allowance for Equity Funds Used During Construction		(14.6)			(16.6)			(13.2)		
Mark-to-Market of Risk Management Contracts		18.8 			19.9 			(33.0)		
Pension Contributions to Qualified Plan Trust		(7.0)			— 			— 		
Deferred Fuel Over/Under-Recovery, Net		37.2 			57.1 			(10.8)		
	
Re-Establishment of Regulatory Asset - Coal Fired Generation		(49.0)			— 			— 		
Change in Other Noncurrent Assets		(40.4)			(38.2)			58.1 		
Change in Other Noncurrent Liabilities		11.2 			(40.3)			(4.8)		
Changes in Certain Components of Working Capital:							
Accounts Receivable, Net		(30.2)			35.7 			33.6 		
Fuel, Materials and Supplies		(38.2)			(93.4)			27.8 		
Accounts Payable		(48.1)			37.7 			(13.3)		
Accrued Taxes, Net		31.3 			(10.2)			(13.2)		
Other Current Assets		18.3 			15.4 			(6.1)		
Other Current Liabilities		(28.3)			(45.5)			42.1 		
Net Cash Flows from Operating Activities		712.0 			661.4 			846.6 		
							
INVESTING ACTIVITIES							
Construction Expenditures		(767.4)			(862.6)			(780.7)		
Change in Advances to Affiliates, Net		0.7 			0.9 			0.5 		
	
Other Investing Activities		8.8 			24.3 			10.8 		
Net Cash Flows Used for Investing Activities		(757.9)			(837.4)			(769.4)		
							
FINANCING ACTIVITIES							
	
Issuance of Long-term Debt – Nonaffiliated		606.9 			478.2 			203.2 		
Change in Advances from Affiliates, Net		(218.1)			31.1 			19.6 		
Retirement of Long-term Debt – Nonaffiliated		(140.3)			(180.5)			(124.0)		

Principal Payments for Finance Lease Obligations		(7.4)			(6.7)			(6.9)		
Dividends Paid on Common Stock		(200.0)			(150.0)			(160.0)		
Other Financing Activities		0.7 			0.9 			1.5 		
Net Cash Flows from (Used for) Financing Activities		41.8 			173.0 			(66.6)		
							
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding		(4.1)			(3.0)			10.6 		
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period		26.8 			29.8 			19.2 		
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period		$	22.7 			$	26.8 			$	29.8 		
							
SUPPLEMENTARY INFORMATION							
Cash Paid for Interest, Net of Capitalized Amounts		$	207.1 			$	190.7 			$	182.0 		
Net Cash Paid (Received) for Income Taxes		— 			63.0 			(13.0)		
Noncash Acquisitions Under Finance Leases		7.2 			8.8 			5.5 		
	
Construction Expenditures Included in Current Liabilities as of December 31,		105.6 			149.7 			134.4 		

							
See Notes to Financial Statements of Registrants beginning on page 229.	
171

INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES

172

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

COMPANY OVERVIEW

As a public utility, I&M engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 602,000 retail customers in its service territory in northern and eastern Indiana and southwestern Michigan.  I&M consolidates Blackhawk Coal Company and Price River Coal Company, its wholly-owned subsidiaries.  I&M also consolidates DCC Fuel.  I&M sells power at wholesale to municipalities and electric cooperatives.  I&M’s River Transportation Division provides barging services to affiliates and nonaffiliated companies.  The revenues from barging represent the majority of other revenues.

AEGCo holds a 50% interest in each of the Rockport Plant units and is entitled to 50% of the capacity and associated energy from each unit. Under unit power agreements approved by the FERC, I&M and KPCo purchase approximately 920 MWs and 390 MWs, respectively, of the output from AEGCo’s 50% share of the Rockport Plant.

To minimize the credit requirements and operating constraints when operating within PJM, participating AEP companies, including I&M, agreed to a netting of certain payment obligations incurred by the participating AEP companies against certain balances due to such AEP companies and to hold PJM harmless from actions that any one or more AEP companies may take with respect to PJM.

173

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales	
						
	Years Ended December 31,	
	2020		2019		2018	
	(in millions of KWhs)	
Retail:						
Residential	5,464 			5,409 			5,731 		
Commercial	4,475 			4,685 			4,851 		
Industrial	7,225 			7,589 			7,836 		
Miscellaneous	67 			69 			71 		
Total Retail	17,231 			17,752 			18,489 		
						
Wholesale	7,135 			8,268 			10,873 		
						
Total KWhs	24,366 			26,020 			29,362 		

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	
						
	Years Ended December 31,	
	2020		2019		2018	
	(in degree days)	
Actual – Heating (a)	3,352 			3,782 			3,886 		
Normal – Heating (b)	3,742 			3,740 			3,747 		
						
Actual – Cooling (c)	928 			940 			1,132 		
Normal – Cooling (b)	854 			849 			849 		

(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.

174

2020 Compared to 2019

Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Net Income
(in millions)

Year Ended December 31, 2019		$	269.4 		
			
Changes in Gross Margin:			
Retail Margins		55.1 		
	
Margins from Off-system Sales		0.1 		
Transmission Revenues		11.0 		
Other Revenues		(10.3)		
Total Change in Gross Margin		55.9 		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		29.2 		
	
Depreciation and Amortization		(61.0)		
Taxes Other Than Income Taxes		(2.0)		
Other Income		(8.2)		

Non-Service Cost Components of Net Periodic Benefit Cost		(1.0)		
Interest Expense		5.6 		
Total Change in Expenses and Other		(37.4)		
			
Income Tax Expense		(3.1)		
			
Year Ended December 31, 2020		$	284.8 		

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 $55 million primarily due to the following:
•A $109 million increase primarily due to the Indiana and Michigan base rate cases and increases in rider revenues. This increase was partially offset in other expense items below.
•A $5 million increase in weather-normalized retail margins primarily in the residential class, partially offset in the commercial and industrial classes.
These increases were partially offset by:
•A $53 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract.
•A $16 million decrease in weather-related usage primarily due to an 11% decrease in heating degree days.
•Transmission Revenues increased $11 million primarily due to the following:
•A $6 million increase from the annual transmission formula rate true-up.
•A $5 million increase from investment in transmission assets.
•Other Revenues decreased $10 million primarily due to a decrease in barging revenues by River Transportation Division (RTD). This decrease was partially offset in Other Operation and Maintenance expenses below.

175

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

•Other Operation and Maintenance expenses decreased $29 million primarily due to the following:
•A $15 million decrease in Cook Plant refueling outage expenses and various maintenance activities.
•An $11 million decrease in nonutility operation expenses primarily due to a decrease in RTD expenses. This decrease was partially offset in Other Revenues above.
•A $10 million decrease in distribution expenses primarily due to a decrease in vegetation management expenses.
•A $9 million decrease due to a charitable contribution to the AEP Foundation in 2019.
•A $7 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2020.
•A $5 million decrease in steam generation expense primarily due to 2019 NSR Consent Decree modifications.
These decreases were partially offset by:
•A $15 million increase in employee-related expenses.
•A $12 million increase in transmission expenses primarily due to a $24 million increase in recoverable PJM expenses, partially offset by an $11 million decrease from the annual transmission formula rate true-up. This increase was partially offset in Retail Margins above.
•Depreciation and Amortization expenses increased $61 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 $8 million primarily due to a decrease in the AFUDC base and the favorable impact of a FERC settlement agreement recorded in 2019.
•Interest Expense decreased $6 million primarily due to lower interest rates on variable rate loans and carrying charges recorded on various riders. This decrease was partially offset by a decrease in AFUDC base.
•Income Tax Expense increased $3 million due to an increase in pretax book income, state tax expense and AFUDC equity partially offset by an increase in amortization of Excess ADIT not subject to normalization requirements. The increase in amortization of Excess ADIT was partially offset in Gross Margin above.
176

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Indiana Michigan Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of income, of comprehensive income (loss), of changes in common shareholder's equity and of cash flows for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.

Change in Accounting Principle

As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that
our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
177

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, whether influenced by issuance of regulatory commission orders, passage of new legislation, or changes in the regulatory environment. As of December 31, 2020, there were $410.2 million of deferred costs included in regulatory assets, $4.3 million of which were pending final regulatory approval, and $2,062.7 million of regulatory liabilities awaiting potential refund or future rate reduction.

The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and applying guidance contained in rate orders and other relevant evidence; which in turn led to significant audit effort and a high degree of auditor subjectivity in performing procedures and in evaluating audit evidence relating to management’s judgments about the probability of recovery of regulatory assets and refund of regulatory liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s assessment of regulatory proceedings, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, including those subject to pending rate cases, also involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, and application of regulatory precedents.

/s/ PricewaterhouseCoopers

Columbus, Ohio
February 25, 2021

We have served as the Company's auditor since 2017.
178

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Indiana Michigan Power Company and Subsidiaries (I&M) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  I&M’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of I&M’s internal control over financial reporting as of December 31, 2020.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013).  Based on management’s assessment, management concluded I&M’s internal control over financial reporting was effective as of December 31, 2020.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, I&M’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit I&M to provide only management’s report in this annual report.
179

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
REVENUES							
Electric Generation, Transmission and Distribution		$	2,165.3 			$	2,222.1 			$	2,272.6 		
Sales to AEP Affiliates		10.5 			10.5 			22.1 		
Other Revenues - Affiliated		60.8 			63.4 			63.4 		
Other Revenues - Nonaffiliated		5.2 			10.7 			12.6 		
TOTAL REVENUES		2,241.8 			2,306.7 			2,370.7 		
							
EXPENSES							
Fuel and Other Consumables Used for Electric Generation		162.0 			190.6 			318.3 		
Purchased Electricity for Resale		182.2 			232.3 			221.8 		
Purchased Electricity from AEP Affiliates		172.8 			214.9 			237.9 		
Other Operation		650.0 			641.2 			585.4 		
Maintenance		193.2 			231.2 			238.1 		
	
Depreciation and Amortization		411.6 			350.6 			293.1 		
Taxes Other Than Income Taxes		107.1 			105.1 			98.9 		
TOTAL EXPENSES		1,878.9 			1,965.9 			1,993.5 		
							
OPERATING INCOME		362.9 			340.8 			377.2 		
							
Other Income (Expense):							
Other Income		10.0 			18.2 			19.2 		

	
Non-Service Cost Components of Net Periodic Benefit Cost		16.7 			17.7 			18.1 		
Interest Expense		(112.3)			(117.9)			(124.1)		
							
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)		277.3 			258.8 			290.4 		
							
Income Tax Expense (Benefit)		(7.5)			(10.6)			29.1 		
							
NET INCOME		$	284.8 			$	269.4 			$	261.3 		
							
The common stock of I&M is wholly-owned by Parent.	
							
See Notes to Financial Statements of Registrants beginning on page 229.	
180

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2020, 2019 and 2018
 (in millions)

		Years Ended December 31,	
		2020		2019		2018	
Net Income		$	284.8 			$	269.4 			$	261.3 		
							
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES							
Cash Flow Hedges, Net of Tax of $0.4, $0.4 and $0.4 in 2020, 2019 and 2018, Respectively		1.6 			1.6 			1.6 		
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0, $0 and $0 in 2020, 2019 and 2018, Respectively		(0.1)			(0.2)			— 		
Pension and OPEB Funded Status, Net of Tax of $0.8, $0.2 and $(0.2) in 2020, 2019 and 2018, Respectively		3.1 			0.8 			(0.6)		
							
TOTAL OTHER COMPREHENSIVE INCOME		4.6 			2.2 			1.0 		
							
TOTAL COMPREHENSIVE INCOME		$	289.4 			$	271.6 			$	262.3 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	
181

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

	Common
Stock		Paid-in
Capital		Retained Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	56.6 			$	980.9 			$	1,192.2 			$	(12.1)			$	2,217.6 		
										
Common Stock Dividends					(124.7)					(124.7)		
ASU 2018-02 Adoption					0.3 			(2.7)			(2.4)		
Net Income					261.3 					261.3 		
Other Comprehensive Income							1.0 			1.0 		
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018	56.6 			980.9 			1,329.1 			(13.8)			2,352.8 		
										
Common Stock Dividends					(80.0)					(80.0)		
	
Net Income					269.4 					269.4 		
Other Comprehensive Income							2.2 			2.2 		
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019	56.6 			980.9 			1,518.5 			(11.6)			2,544.4 		
										
Common Stock Dividends					(85.0)					(85.0)		
ASU 2016-13 Adoption					0.4 					0.4 		
Net Income					284.8 					284.8 		
Other Comprehensive Income							4.6 			4.6 		
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020	$	56.6 			$	980.9 			$	1,718.7 			$	(7.0)			$	2,749.2 		
										
See Notes to Financial Statements of Registrants beginning on page 229.	

182

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2020 and 2019
(in millions)

		December 31,	
		2020		2019	
CURRENT ASSETS					
Cash and Cash Equivalents		$	3.3 			$	2.0 		
Advances to Affiliates		13.3 			13.2 		
Accounts Receivable:					
Customers		44.0 			53.6 		
Affiliated Companies		51.3 			53.7 		
Accrued Unbilled Revenues		— 			2.5 		
Miscellaneous		2.0 			0.3 		
Allowance for Uncollectible Accounts		(0.3)			(0.6)		
Total Accounts Receivable		97.0 			109.5 		
Fuel		86.0 			56.2 		
Materials and Supplies		175.8 			171.3 		
Risk Management Assets		3.6 			9.8 		
	
Accrued Tax Benefits		10.3 			— 		
Regulatory Asset for Under-Recovered Fuel Costs		5.4 			3.0 		
Accrued Reimbursement of Spent Nuclear Fuel Costs		14.2 			24.0 		
Prepayments and Other Current Assets		9.9 			14.0 		
TOTAL CURRENT ASSETS		418.8 			403.0 		
					
PROPERTY, PLANT AND EQUIPMENT					
Electric:					
Generation		5,264.7 			5,099.7 		
Transmission		1,696.4 			1,641.8 		
Distribution		2,594.6 			2,437.6 		
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)		686.7 			632.6 		
Construction Work in Progress		362.4 			382.3 		
Total Property, Plant and Equipment		10,604.8 			10,194.0 		
Accumulated Depreciation, Depletion and Amortization		3,552.5 			3,294.3 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		7,052.3 			6,899.7 		
					
OTHER NONCURRENT ASSETS					
Regulatory Assets		404.8 			482.1 		
Spent Nuclear Fuel and Decommissioning Trusts		3,306.7 			2,975.7 		
	
Operating Lease Assets		218.1 			294.9 		
Deferred Charges and Other Noncurrent Assets		237.6 			182.0 		
TOTAL OTHER NONCURRENT ASSETS		4,167.2 			3,934.7 		
					
TOTAL ASSETS		$	11,638.3 			$	11,237.4 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	

183

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
December 31, 2020 and 2019
(dollars in millions)

		December 31,	
		2020		2019	
CURRENT LIABILITIES					
Advances from Affiliates		$	103.0 			$	114.4 		
Accounts Payable:					
General		153.2 			169.4 		
Affiliated Companies		80.5 			68.4 		
Long-term Debt Due Within One Year – Nonaffiliated
(December 31, 2020 and 2019 Amounts Include $75.7 and $86.1 Respectively, Related to DCC Fuel)		369.6 			139.7 		
	
Customer Deposits		41.7 			39.4 		
Accrued Taxes		102.5 			112.4 		
Accrued Interest		35.6 			36.2 		
Obligations Under Operating Leases		85.6 			87.3 		
Regulatory Liability for Over-Recovered Fuel Costs		20.8 			6.1 		
Other Current Liabilities		112.0 			110.1 		
TOTAL CURRENT LIABILITIES		1,104.5 			883.4 		
					
NONCURRENT LIABILITIES					
Long-term Debt – Nonaffiliated		2,660.3 			2,910.5 		
	
Deferred Income Taxes		1,064.4 			979.7 		
Regulatory Liabilities and Deferred Investment Tax Credits		2,041.9 			1,891.4 		
Asset Retirement Obligations		1,812.9 			1,748.6 		
Obligations Under Operating Leases		135.9 			211.6 		
Deferred Credits and Other Noncurrent Liabilities		69.2 			67.8 		
TOTAL NONCURRENT LIABILITIES		7,784.6 			7,809.6 		
					
TOTAL LIABILITIES		8,889.1 			8,693.0 		
					
Rate Matters (Note 4)					
Commitments and Contingencies (Note 6)					
					
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		1,718.7 			1,518.5 		
Accumulated Other Comprehensive Income (Loss)		(7.0)			(11.6)		
TOTAL COMMON SHAREHOLDER’S EQUITY		2,749.2 			2,544.4 		
					
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	11,638.3 			$	11,237.4 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	
184

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
OPERATING ACTIVITIES			
Net Income		$	284.8 			$	269.4 			$	261.3 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:							
Depreciation and Amortization		411.6 			350.6 			293.1 		
Rockport Plant, Unit 2 Operating Lease Amortization		69.2 			69.2 			— 		
Deferred Income Taxes		(16.2)			(52.7)			(42.9)		
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net		24.4 			(26.4)			29.2 		

Allowance for Equity Funds Used During Construction		(11.5)			(19.4)			(11.9)		
Mark-to-Market of Risk Management Contracts		5.9 			(0.6)			(4.1)		
Amortization of Nuclear Fuel		87.5 			89.1 			113.8 		
Pension Contributions to Qualified Plan Trust		(6.4)			— 			— 		
Deferred Fuel Over/Under-Recovery, Net		12.4 			(24.3)			39.7 		
	
Change in Other Noncurrent Assets		6.1 			8.3 			(36.5)		
Change in Other Noncurrent Liabilities		45.0 			33.7 			72.1 		
Changes in Certain Components of Working Capital:							
Accounts Receivable, Net		14.5 			35.4 			4.8 		
Fuel, Materials and Supplies		(34.7)			(22.4)			(11.2)		
Accounts Payable		(10.8)			3.6 			(14.1)		
	
Accrued Taxes, Net		(20.2)			48.3 			41.2 		
	
Rockport Plant, Unit 2 Operating Lease Payments		(73.9)			(73.9)			— 		
Other Current Assets		14.3 			11.2 			1.5 		
Other Current Liabilities		(25.7)			(13.9)			(10.3)		
Net Cash Flows from Operating Activities		776.3 			685.2 			725.7 		
							
INVESTING ACTIVITIES							
Construction Expenditures		(544.7)			(585.9)			(568.5)		
Change in Advances to Affiliates, Net		(0.1)			(0.5)			(0.3)		
Purchases of Investment Securities		(1,637.2)			(1,531.0)			(2,064.7)		
Sales of Investment Securities		1,593.4 			1,473.0 			2,010.0 		
Acquisitions of Nuclear Fuel		(69.7)			(92.3)			(46.1)		
	
Other Investing Activities		9.4 			16.6 			14.8 		
Net Cash Flows Used for Investing Activities		(648.9)			(720.1)			(654.8)		
							
FINANCING ACTIVITIES							
Issuance of Long-term Debt - Nonaffiliated		69.5 			123.3 			1,168.1 		
Change in Advances from Affiliates, Net		(11.4)			113.3 			(210.5)		
Retirement of Long-term Debt - Nonaffiliated		(93.2)			(117.1)			(884.9)		
	
Principal Payments for Finance Lease Obligations		(6.5)			(5.7)			(8.8)		
Dividends Paid on Common Stock		(85.0)			(80.0)			(124.7)		
Other Financing Activities		0.5 			0.7 			(9.0)		
Net Cash Flows from (Used for) Financing Activities		(126.1)			34.5 			(69.8)		
							
Net Increase (Decrease) in Cash and Cash Equivalents		1.3 			(0.4)			1.1 		
Cash and Cash Equivalents at Beginning of Period		2.0 			2.4 			1.3 		
Cash and Cash Equivalents at End of Period		$	3.3 			$	2.0 			$	2.4 		
							
SUPPLEMENTARY INFORMATION							
Cash Paid for Interest, Net of Capitalized Amounts		$	107.6 			$	111.9 			$	116.9 		
Net Cash Paid for Income Taxes		42.1 			3.4 			32.6 		
Noncash Acquisitions Under Finance Leases		3.0 			11.9 			5.8 		
Construction Expenditures Included in Current Liabilities as of December 31,		62.8 			86.0 			93.0 		
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,		33.4 			0.1 			4.0 		
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage		2.6 			0.3 			2.2 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	
185

OHIO POWER COMPANY AND SUBSIDIARIES

186

OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

COMPANY OVERVIEW

As a public utility, OPCo engages in the transmission and distribution of power to approximately 1,507,000 retail customers in the northwestern, central, eastern and southern sections of Ohio. Effective January 2014, OPCo purchases power from both affiliated and nonaffiliated entities, subject to auction requirements and PUCO approval, to meet the energy and capacity needs of its remaining SSO customers.  OPCo consolidates Ohio Phase-in-Recovery Funding LLC, its wholly-owned subsidiary. The Ohio Phase-in-Recovery Funding LLC securitization bonds matured in July 2019.

To minimize the credit requirements and operating constraints when operating within PJM, participating AEP companies, including OPCo, agreed to a netting of certain payment obligations incurred by the participating AEP companies against certain balances due to such AEP companies and to hold PJM harmless from actions that any one or more AEP companies may take with respect to PJM.

187

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales		
							
	Years Ended December 31,	
	2020		2019		2018		
	(in millions of KWhs)		
Retail:							
Residential	14,355 			14,411 			14,940 			
Commercial	13,933 			14,599 			14,655 			
Industrial	13,347 			14,407 			14,857 			
Miscellaneous	113 			114 			115 			
Total Retail (a)	41,748 			43,531 			44,567 			
							
Wholesale (b)	1,859 			2,335 			2,441 			
							
Total KWhs	43,607 			45,866 			47,008 			

(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold into 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	
						
	Years Ended December 31,	
	2020		2019		2018	
	(in degree days)	
Actual – Heating (a)	2,743 			3,071 			3,357 		
Normal – Heating (b)	3,202 			3,208 			3,215 		
						
Actual – Cooling (c)	1,140 			1,224 			1,402 		
Normal – Cooling (b)	1,006 			992 			980 		

(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.

188

2020 Compared to 2019

Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Net Income
(in millions)

Year Ended December 31, 2019		$	297.1 		
			
Changes in Gross Margin:			
Retail Margins		58.8 		
Margins from Off-system Sales		10.7 		
Transmission Revenues		22.6 		
Other Revenues		19.1 		
Total Change in Gross Margin		111.2 		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		(57.0)		
Depreciation and Amortization		(35.7)		
Taxes Other Than Income Taxes		(16.0)		
Interest Income		(2.2)		
Carrying Costs Income		0.6 		
Allowance for Equity Funds Used During Construction		(5.7)		
Non-Service Cost Components of Net Periodic Benefit Cost		0.4 		
Interest Expense		(11.0)		
Total Change in Expenses and Other		(126.6)		
			
Income Tax Expense		(10.3)		
			
Year Ended December 31, 2020		$	271.4 		

The major components of the increase 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 $59 million primarily due to the following:
•A $69 million net increase related to other various rider revenues. This increase was partially offset in other expense items below.
•A $61 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.
•A $6 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.
These increases were partially offset by:
•A $58 million decrease due to a reversal of a regulatory provision in the first quarter of 2019.
•A $17 million net decrease in margin for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.
•A $10 million decrease in usage primarily in the commercial class, partially offset by an increase in the retail class.
•Margins from Off-system Sales increased $11 million primarily due to the following:
•A $26 million increase due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above.
This increase was partially offset by:
•A $17 million decrease in sales due to lower market prices and decreased sales volumes in 2020. This decrease was offset in Retail Margins above.
•Transmission Revenues increased $23 million primarily due to the following:
•A $16 million increase from the annual transmission formula rate true-up.
•A $6 million increase due to additional investment in transmission assets.
189

•Other Revenues increased $19 million primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.

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

•Other Operation and Maintenance expenses increased $57 million primarily due to the following:
•A $62 million net increase in transmission expenses, primarily due to a $94 million increase in recoverable PJM expenses, partially offset by a $28 million decrease related to the annual transmission formula rate true-up. This increase was offset in Gross Margins above.
•A $19 million increase in remitted Universal Service Fund 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.
These increases were partially offset by:
•A $12 million decrease in recoverable distribution expenses primarily related to vegetation management. This decrease was offset in Retail Margins above.
•A $5 million decrease due to a charitable contribution to the AEP Foundation in 2019.
•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Retail Margins above.
•Depreciation and Amortization expenses increased $36 million primarily due to the following:
•A $22 million increase in recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•A $19 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•An $11 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 $6 million increase due to prior year under-recovery of revenues associated with the Deferred Asset Phase-In-Recovery securitization which ended in the 2nd quarter of 2019. This decrease was offset in Retail Margins above.
These increases were partially offset by:
•A $24 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 $16 million primarily due to the following:
•A $22 million increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
This increase was partially offset by:
•A $6 million decrease in excise taxes due to lower demand in 2020. This decrease was offset in Retail Margins above.
•Allowance for Equity Funds Used During Construction decreased $6 million primarily due to adjustments that resulted from 2019 FERC audit findings and a decrease in AFUDC base.
•Interest Expense increased $11 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $10 million primarily due to an increase in tax expense for benefits previously flowed through to customers.
190

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Ohio Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Ohio Power Company and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of income, of comprehensive income (loss), of changes in common shareholder's equity and of cash flows for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.

Change in Accounting Principle

As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
191

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, whether influenced by issuance of regulatory commission orders, passage of new legislation, or changes in the regulatory environment. As of December 31, 2020, there were $385.8 million of deferred costs included in regulatory assets, $8.4 million of which were pending final regulatory approval, and $1,009.1 million of regulatory liabilities awaiting potential refund or future rate reduction, $0.2 million of which were pending final regulatory determination.

The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and applying guidance contained in rate orders and other relevant evidence; which in turn led to significant audit effort and a high degree of auditor subjectivity in performing procedures and in evaluating audit evidence relating to management’s judgments about the probability of recovery of regulatory assets and refund of regulatory liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s assessment of regulatory proceedings, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, including those subject to pending rate cases, also involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, and application of regulatory precedents.

Valuation of Level 3 Risk Management Commodity Contracts

As described in Notes 1, 10 and 11 to the consolidated financial statements, the Company employs risk management commodity contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, over-the-counter swaps and options to accomplish its risk management strategies. Certain over-the-counter and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. The fair value of these risk management commodity contracts is estimated based on available market information including valuation models that estimate future energy prices based on existing market and broker quotes, and other assumptions. Fair value estimates involve significant uncertainties and matters of significant judgement including future commodity prices and future price volatility. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. Management utilized such unobservable pricing data to value its Level 3 risk management commodity contract liabilities, which totaled $110.3
million, as of December 31, 2020.

The principal considerations for our determination that performing procedures relating to the valuation of Level 3 risk management commodity contracts is a critical audit matter are the significant judgment and estimation by management when developing the fair value of the commodity contracts; which in turn led to significant audit effort and a high degree of auditor subjectivity in performing procedures and in evaluating audit evidence relating to the unobservable assumptions for projections of future commodity prices and future price volatilities used within management’s discounted cash flow models. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in performing these procedures and evaluating the audit evidence obtained.

192

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s valuation of the risk management commodity contracts, including controls over the assumptions used to value the Level 3 risk management commodity contracts. These procedures also included, among others, testing the data used in and management’s process for developing the fair value of the Level 3 risk management commodity contracts. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the discounted cash flow models and reasonableness of the future commodity prices and future price volatilities assumptions.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

We have served as the Company's auditor since 2017.
193

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Ohio Power Company and Subsidiaries (OPCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  OPCo’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of OPCo’s internal control over financial reporting as of December 31, 2020.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013).  Based on management’s assessment, management concluded OPCo’s internal control over financial reporting was effective as of December 31, 2020.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, OPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit OPCo to provide only management’s report in this annual report.
194

OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
REVENUES							
Electricity, Transmission and Distribution		$	2,698.6 			$	2,759.5 			$	3,033.8 		
Sales to AEP Affiliates		41.5 			27.3 			21.0 		
Other Revenues		9.0 			10.8 			8.6 		
TOTAL REVENUES		2,749.1 			2,797.6 			3,063.4 		
							
EXPENSES							
Purchased Electricity for Resale		549.2 			607.3 			684.6 		
Purchased Electricity from AEP Affiliates		119.7 			156.0 			135.3 		
	
Amortization of Generation Deferrals		— 			65.3 			223.9 		
Other Operation		822.6 			742.6 			771.3 		
Maintenance		127.1 			150.1 			156.0 		
Depreciation and Amortization		276.6 			240.9 			259.7 		
Taxes Other Than Income Taxes		450.2 			434.2 			412.8 		
TOTAL EXPENSES		2,345.4 			2,396.4 			2,643.6 		
							
OPERATING INCOME		403.7 			401.2 			419.8 		
							
Other Income (Expense):							
Interest Income		1.0 			3.2 			3.4 		
Carrying Costs Income		1.6 			1.0 			1.7 		
Allowance for Equity Funds Used During Construction		12.5 			18.2 			9.8 		
Non-Service Cost Components of Net Periodic Benefit Cost		15.0 			14.6 			15.5 		
Interest Expense		(117.2)			(106.2)			(100.7)		
							
INCOME BEFORE INCOME TAX EXPENSE		316.6 			332.0 			349.5 		
							
Income Tax Expense		45.2 			34.9 			24.0 		
							
NET INCOME		$	271.4 			$	297.1 			$	325.5 		
							
The common stock of OPCo is wholly-owned by Parent.	
							
See Notes to Financial Statements of Registrants beginning on page 229.	
195

OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
Net Income		$	271.4 			$	297.1 			$	325.5 		
							
OTHER COMPREHENSIVE LOSS, NET OF TAXES							
Cash Flow Hedges, Net of Tax of $0, $(0.3) and $(0.4) in 2020, 2019 and 2018, Respectively		— 			(1.0)			(1.3)		
							
TOTAL COMPREHENSIVE INCOME		$	271.4 			$	296.1 			$	324.2 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	
196

OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

	Common
Stock		Paid-in
Capital		Retained Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	321.2 			$	838.8 			$	1,148.4 			$	1.9 			$	2,310.3 		
										
Common Stock Dividends					(337.5)					(337.5)		
ASU 2018-02 Adoption							0.4 			0.4 		
Net Income					325.5 					325.5 		
Other Comprehensive Loss							(1.3)			(1.3)		
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018	321.2 			838.8 			1,136.4 			1.0 			2,297.4 		
										
Common Stock Dividends					(85.0)					(85.0)		
Net Income					297.1 					297.1 		
Other Comprehensive Loss							(1.0)			(1.0)		
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019	321.2 			838.8 			1,348.5 			— 			2,508.5 		
										
Common Stock Dividends					(87.5)					(87.5)		
ASU 2016-13 Adoption					0.3 					0.3 		
Net Income					271.4 					271.4 		
	
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020	$	321.2 			$	838.8 			$	1,532.7 			$	— 			$	2,692.7 		
										
See Notes to Financial Statements of Registrants beginning on page 229.	
197

OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2020 and 2019
(in millions)

		December 31,	
		2020		2019	
CURRENT ASSETS					
Cash and Cash Equivalents		$	7.4 			$	3.7 		

Accounts Receivable:					
Customers		50.0 			53.0 		
Affiliated Companies		65.1 			59.3 		
Accrued Unbilled Revenues		14.8 			20.3 		
Miscellaneous		3.9 			0.5 		
Allowance for Uncollectible Accounts		(0.6)			(0.7)		
Total Accounts Receivable		133.2 			132.4 		
Materials and Supplies		66.9 			52.3 		
Renewable Energy Credits		29.5 			30.9 		

Prepayments and Other Current Assets		19.3 			19.2 		
TOTAL CURRENT ASSETS		256.3 			238.5 		
					
PROPERTY, PLANT AND EQUIPMENT					
Electric:					
Transmission		2,831.9 			2,686.3 		
Distribution		5,708.3 			5,323.5 		
Other Property, Plant and Equipment		899.6 			765.8 		
Construction Work in Progress		362.3 			394.4 		
Total Property, Plant and Equipment		9,802.1 			9,170.0 		
Accumulated Depreciation and Amortization		2,350.0 			2,263.0 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		7,452.1 			6,907.0 		
					
OTHER NONCURRENT ASSETS					
Regulatory Assets		385.8 			351.8 		

Deferred Charges and Other Noncurrent Assets		616.2 			546.3 		
TOTAL OTHER NONCURRENT ASSETS		1,002.0 			898.1 		
					
TOTAL ASSETS		$	8,710.4 			$	8,043.6 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	
198

OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
December 31, 2020 and 2019
(dollars in millions)

		December 31,	
		2020		2019	
CURRENT LIABILITIES					
Advances from Affiliates		$	259.2 			$	131.0 		
Accounts Payable:					
General		181.0 			233.7 		
Affiliated Companies		118.4 			103.6 		
Long-term Debt Due Within One Year – Nonaffiliated		500.1 			0.1 		
Risk Management Liabilities		8.7 			7.3 		
Customer Deposits		55.1 			70.6 		
Accrued Taxes		631.0 			587.9 		
	
Obligations Under Operating Leases		13.1 			12.5 		
Other Current Liabilities		139.6 			151.2 		
TOTAL CURRENT LIABILITIES		1,906.2 			1,297.9 		
					
NONCURRENT LIABILITIES					
Long-term Debt – Nonaffiliated		1,930.1 			2,081.9 		
Long-term Risk Management Liabilities		101.6 			96.3 		
Deferred Income Taxes		955.1 			849.4 		
Regulatory Liabilities and Deferred Investment Tax Credits		1,005.2 			1,090.9 		
	
Obligations Under Operating Leases		79.5 			76.0 		
Deferred Credits and Other Noncurrent Liabilities		40.0 			42.7 		
TOTAL NONCURRENT LIABILITIES		4,111.5 			4,237.2 		
					
TOTAL LIABILITIES		6,017.7 			5,535.1 		
					
Rate Matters (Note 4)					
Commitments and Contingencies (Note 6)					
					
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		1,532.7 			1,348.5 		
	
TOTAL COMMON SHAREHOLDER’S EQUITY		2,692.7 			2,508.5 		
					
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	8,710.4 			$	8,043.6 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	
199

OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
OPERATING ACTIVITIES							
Net Income		$	271.4 			$	297.1 			$	325.5 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:							
Depreciation and Amortization		276.6 			240.9 			259.7 		
	
Amortization of Generation Deferrals		— 			65.3 			223.9 		
Deferred Income Taxes		77.2 			43.8 			(36.2)		
	
Allowance for Equity Funds Used During Construction		(12.5)			(18.2)			(9.8)		
Mark-to-Market of Risk Management Contracts		6.7 			4.0 			(32.2)		
	
Property Taxes		(16.6)			(33.7)			(12.5)		
	
Refund of Global Settlement		— 			(16.5)			(5.5)		
Reversal of Regulatory Provision		— 			(56.2)			— 		
Change in Regulatory Assets		(69.4)			(20.1)			171.5 		
Change in Other Noncurrent Assets		(49.4)			(35.3)			(11.5)		
Change in Other Noncurrent Liabilities		(66.4)			(93.2)			53.8 		
Changes in Certain Components of Working Capital:							
Accounts Receivable, Net		4.2 			75.0 			43.1 		
Materials and Supplies		(23.9)			(16.4)			(11.3)		
Accounts Payable		10.3 			0.4 			(13.8)		
Accrued Taxes, Net		43.3 			38.7 			26.8 		
Other Current Assets		1.9 			0.8 			8.1 		
Other Current Liabilities		(42.5)			(55.2)			49.1 		
Net Cash Flows from Operating Activities		410.9 			421.2 			1,028.7 		
							
INVESTING ACTIVITIES							
Construction Expenditures		(813.2)			(799.2)			(725.9)		
	
Other Investing Activities		22.2 			55.1 			18.4 		
Net Cash Flows Used for Investing Activities		(791.0)			(744.1)			(707.5)		
							
FINANCING ACTIVITIES							
Issuance of Long-term Debt – Nonaffiliated		347.0 			444.3 			392.8 		
Change in Advances from Affiliates, Net		128.2 			16.9 			26.3 		
Retirement of Long-term Debt – Nonaffiliated		(0.1)			(80.3)			(397.1)		
	
Principal Payments for Finance Lease Obligations		(4.7)			(3.5)			(3.8)		
Dividends Paid on Common Stock		(87.5)			(85.0)			(337.5)		
Other Financing Activities		0.9 			1.7 			0.9 		
Net Cash Flows from (Used for) Financing Activities		383.8 			294.1 			(318.4)		
							
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding		3.7 			(28.8)			2.8 		
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period		3.7 			32.5 			29.7 		
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period		$	7.4 			$	3.7 			$	32.5 		
							
SUPPLEMENTARY INFORMATION							
Cash Paid for Interest, Net of Capitalized Amounts		$	111.2 			$	100.6 			$	97.1 		
Net Cash Paid (Received) for Income Taxes		(26.9)			7.3 			51.3 		
Noncash Acquisitions Under Finance Leases		6.1 			11.3 			4.4 		
Construction Expenditures Included in Current Liabilities as of December 31,		76.7 			125.9 			98.2 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	
200

PUBLIC SERVICE COMPANY OF OKLAHOMA

201

PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

COMPANY OVERVIEW

As a public utility, PSO engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 565,000 retail customers in its service territory in eastern and southwestern Oklahoma.  PSO sells electric power at wholesale to other utilities, municipalities and electric cooperatives.

202

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales	
						
	Years Ended December 31,	
	2020		2019		2018	
	(in millions of KWhs)	
Retail:						
Residential	6,117 			6,273 			6,452 		
Commercial	4,673 			4,958 			5,005 		
Industrial	5,713 			6,156 			6,120 		
Miscellaneous	1,199 			1,246 			1,263 		
Total Retail	17,702 			18,633 			18,840 		
						
Wholesale	345 			714 			758 		
						
Total KWhs	18,047 			19,347 			19,598 		

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	
						
	Years Ended December 31,	
	2020		2019		2018	
	(in degree days)	
Actual – Heating (a)	1,454 			1,846 			1,886 		
Normal – Heating (b)	1,744 			1,751 			1,752 		
						
Actual – Cooling (c)	2,069 			2,265 			2,445 		
Normal – Cooling (b)	2,174 			2,160 			2,149 		

(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.
203

2020 Compared to 2019

Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Net Income
(in millions)

Year Ended December 31, 2019		$	137.6 		
			
Changes in Gross Margin:			
Retail Margins (a)		(14.0)		
Margins from Off-system Sales		(1.6)		
Transmission Revenues		1.9 		
Other Revenues		8.5 		
Total Change in Gross Margin		(5.2)		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		(10.0)		
Depreciation and Amortization		(4.0)		
Taxes Other Than Income Taxes		(4.2)		
Interest Income		(1.1)		
Allowance for Funds Used During Construction		1.3 		
Non-Service Cost Components of Net Periodic Benefit Cost		0.1 		
Interest Expense		6.2 		
Total Change in Expenses and Other		(11.7)		
			
Income Tax Expense		2.3 		
			
Year Ended December 31, 2020		$	123.0 		

(a)Includes firm wholesale sales to municipals and cooperatives.

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 $14 million primarily due to the following:
•A $15 million decrease in weather-related usage due to a 21% decrease in heating degree days and a 9% decrease in cooling degree days.
•A $13 million decrease in revenue from rate riders. This decrease was partially offset in other expense items below.
•An $8 million decrease due to customer refunds related to Tax Reform. This decrease is partially offset in Income Tax Expense.
These decreases were partially offset by:
•An $11 million increase in weather-normalized margins primarily in the residential class.
•A $10 million increase due to new base rates implemented in April 2019.
•Other Revenues increased $9 million primarily due to business development revenue. This increase was offset in other expense items below.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $10 million primarily due to the following:
•A $20 million increase in transmission expenses primarily due to the annual transmission formula rate true-up. This increase was partially offset in Retail Margins above.
•A $9 million increase in business development expenses. This increase was offset in Other Revenues above.
•A $6 million increase in customer-related expenses primarily related to energy efficiency programs. This increase was partially offset in Retail Margins above.
204

These increases were partially offset by:
•A $7 million decrease in administrative and general expenses primarily due to the receipt of an insurance settlement.
•A $6 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs.
•A $4 million decrease in expenses at various generation plants.
•A $3 million decrease due to a charitable contribution to the AEP Foundation in 2019.
•A $3 million decrease in fees for factoring accounts receivable.
•Depreciation and Amortization expenses increased $4 million primarily due to higher a depreciable base.
•Taxes Other Than Income Taxes increased $4 million primarily due to increased property taxes.
•Interest Expense decreased $6 million primarily due to lower interest rates on long-term debt.

205

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Public Service Company of Oklahoma

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Public Service Company of Oklahoma (the “Company”) as of December 31, 2020 and 2019, and the related statements of income, of comprehensive income (loss), of changes in common shareholder's equity and of cash flows for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.

Change in Accounting Principle

As discussed in Note 13 to the financial statements, the Company changed the manner in which it accounts for leases in 2019.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

206

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the financial statements, the Company’s financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, whether influenced by issuance of regulatory commission orders, passage of new legislation, or changes in the regulatory environment. As of December 31, 2020, there were $405.1 million of deferred costs included in regulatory assets, $50.5 million of which were pending final regulatory approval, and $802.2 million of regulatory liabilities awaiting potential refund or future rate reduction.

The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and applying guidance contained in rate orders and other relevant evidence; which in turn led to significant audit effort and a high degree of auditor subjectivity in performing procedures and in evaluating audit evidence relating to management’s judgments about the probability of recovery of regulatory assets and refund of regulatory liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to management’s assessment of regulatory proceedings, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, including those subject to pending rate cases, also involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, and application of regulatory precedents.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

We have served as the Company's auditor since 2017.
207

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Public Service Company of Oklahoma (PSO) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  PSO’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of PSO’s internal control over financial reporting as of December 31, 2020.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013).  Based on management’s assessment, management concluded PSO’s internal control over financial reporting was effective as of December 31, 2020.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, PSO’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit PSO to provide only management’s report in this annual report.
208

PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF INCOME
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
REVENUES							
Electric Generation, Transmission and Distribution		$	1,246.1 			$	1,469.6 			$	1,537.6 		
Sales to AEP Affiliates		5.2 			6.1 			5.4 		
Other Revenues		14.8 			6.1 			4.3 		
TOTAL REVENUES		1,266.1 			1,481.8 			1,547.3 		
							
EXPENSES							
Fuel and Other Consumables Used for Electric Generation		15.6 			195.1 			240.5 		
Purchased Electricity for Resale		427.9 			458.9 			479.9 		
	
Other Operation		327.3 			315.0 			372.8 		
Maintenance		98.4 			100.7 			104.8 		
Depreciation and Amortization		173.5 			169.5 			164.0 		
Taxes Other Than Income Taxes		47.5 			43.3 			42.8 		
TOTAL EXPENSES		1,090.2 			1,282.5 			1,404.8 		
							
OPERATING INCOME		175.9 			199.3 			142.5 		
							
Other Income (Expense):							
Interest Income		0.1 			1.2 			0.1 		
	
Allowance for Equity Funds Used During Construction		4.0 			2.7 			0.4 		
Non-Service Cost Components of Net Periodic Benefit Cost		8.5 			8.4 			8.7 		
Interest Expense		(60.3)			(66.5)			(63.5)		
							
INCOME BEFORE INCOME TAX EXPENSE		128.2 			145.1 			88.2 		
							
Income Tax Expense		5.2 			7.5 			5.0 		
							
NET INCOME		$	123.0 			$	137.6 			$	83.2 		
							
The common stock of PSO is wholly-owned by Parent.	
							
See Notes to Financial Statements of Registrants beginning on page 229.	

209

PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2020, 2019 and 2018
 (in millions)

		Years Ended December 31,	
		2020		2019		2018	
Net Income		$	123.0 			$	137.6 			$	83.2 		
							
OTHER COMPREHENSIVE LOSS, NET OF TAXES							
Cash Flow Hedges, Net of Tax of $(0.3), $(0.3) and $(0.3) in 2020, 2019 and 2018, Respectively		(1.0)			(1.0)			(1.0)		
							
TOTAL COMPREHENSIVE INCOME		$	122.0 			$	136.6 			$	82.2 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	

210

PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

	Common
Stock		Paid-in
Capital		Retained Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	157.2 			$	364.0 			$	691.5 			$	2.6 			$	1,215.3 		
										
Common Stock Dividends					(50.0)					(50.0)		
ASU 2018-02 Adoption							0.5 			0.5 		
Net Income					83.2 					83.2 		
Other Comprehensive Loss							(1.0)			(1.0)		
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					137.6 					137.6 		
Other Comprehensive Loss							(1.0)			(1.0)		
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019	157.2 			364.0 			851.0 			1.1 			1,373.3 		
										
Capital Contribution of Radial Assets from Parent			50.0 							50.0 		
	
ASU 2016-13 Adoption					0.3 					0.3 		
Net Income					123.0 					123.0 		
Other Comprehensive Loss							(1.0)			(1.0)		
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020	$	157.2 			$	414.0 			$	974.3 			$	0.1 			$	1,545.6 		
										
See Notes to Financial Statements of Registrants beginning on page 229.	

211

PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
ASSETS
December 31, 2020 and 2019
(in millions)

		December 31,	
		2020		2019	
CURRENT ASSETS					
Cash and Cash Equivalents		$	2.6 			$	1.5 		
Advances to Affiliates		— 			38.8 		
Accounts Receivable:					
Customers		30.8 			28.9 		
Affiliated Companies		15.6 			20.6 		
Miscellaneous		2.0 			0.6 		
Allowance for Uncollectible Accounts		— 			(0.3)		
Total Accounts Receivable		48.4 			49.8 		
Fuel		17.9 			12.2 		
Materials and Supplies		54.0 			46.8 		
Risk Management Assets		10.3 			15.8 		
Accrued Tax Benefits		10.9 			11.3 		
Regulatory Asset for Under-Recovered Fuel Costs		30.1 			— 		
Prepayments and Other Current Assets		7.1 			12.0 		
TOTAL CURRENT ASSETS		181.3 			188.2 		
					
PROPERTY, PLANT AND EQUIPMENT					
Electric:					
Generation		1,480.7 			1,574.6 		
Transmission		1,069.9 			948.5 		
Distribution		2,853.0 			2,684.8 		
Other Property, Plant and Equipment		393.3 			342.1 		
Construction Work in Progress		128.7 			133.4 		
Total Property, Plant and Equipment		5,925.6 			5,683.4 		
Accumulated Depreciation and Amortization		1,605.6 			1,580.1 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		4,320.0 			4,103.3 		
					
OTHER NONCURRENT ASSETS					
Regulatory Assets		375.0 			375.2 		
	
Employee Benefits and Pension Assets		65.8 			43.9 		
Operating Lease Assets		42.6 			36.8 		
Deferred Charges and Other Noncurrent Assets		6.0 			4.1 		
TOTAL OTHER NONCURRENT ASSETS		489.4 			460.0 		
					
TOTAL ASSETS		$	4,990.7 			$	4,751.5 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	

212

PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
December 31, 2020 and 2019

		December 31,	
		2020		2019	
		(in millions)	
CURRENT LIABILITIES					
Advances from Affiliates		$	155.4 			$	— 		
Accounts Payable:					
General		107.0 			134.3 		
Affiliated Companies		43.4 			59.3 		
Long-term Debt Due Within One Year – Nonaffiliated		0.5 			13.2 		
	
Customer Deposits		54.8 			58.9 		
Accrued Taxes		26.8 			22.9 		
	
Obligations Under Operating Leases		6.5 			5.8 		
Regulatory Liability for Over-Recovered Fuel Costs		— 			63.9 		
	
Other Current Liabilities		84.2 			87.5 		
TOTAL CURRENT LIABILITIES		478.6 			445.8 		
					
NONCURRENT LIABILITIES					
Long-term Debt – Nonaffiliated		1,373.3 			1,373.0 		
Deferred Income Taxes		688.5 			628.3 		
Regulatory Liabilities and Deferred Investment Tax Credits		802.2 			837.2 		
Asset Retirement Obligations		45.7 			44.5 		
	
Obligations Under Operating Leases		36.2 			31.0 		
Deferred Credits and Other Noncurrent Liabilities		20.6 			18.4 		
TOTAL NONCURRENT LIABILITIES		2,966.5 			2,932.4 		
					
TOTAL LIABILITIES		3,445.1 			3,378.2 		
					
Rate Matters (Note 4)					
Commitments and Contingencies (Note 6)					
					
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		414.0 			364.0 		
Retained Earnings		974.3 			851.0 		
Accumulated Other Comprehensive Income (Loss)		0.1 			1.1 		
TOTAL COMMON SHAREHOLDER’S EQUITY		1,545.6 			1,373.3 		
					
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY		$	4,990.7 			$	4,751.5 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	

213

PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
OPERATING ACTIVITIES							
Net Income		$	123.0 			$	137.6 			$	83.2 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:							
Depreciation and Amortization		173.5 			169.5 			164.0 		
Deferred Income Taxes		17.0 			(18.2)			(31.1)		
	
Allowance for Equity Funds Used During Construction		(4.0)			(2.7)			(0.4)		
Mark-to-Market of Risk Management Contracts		5.5 			(6.4)			(3.0)		

Deferred Fuel Over/Under-Recovery, Net		(94.0)			43.8 			57.4 		

Change in Other Noncurrent Assets		(17.9)			5.7 			— 		
Change in Other Noncurrent Liabilities		1.6 			(7.3)			21.4 		
Changes in Certain Components of Working Capital:							
Accounts Receivable, Net		1.4 			15.4 			5.1 		
Fuel, Materials and Supplies		(14.1)			(1.9)			(2.6)		
Accounts Payable		(29.5)			7.0 			17.7 		
Accrued Taxes, Net		3.6 			3.9 			13.2 		
Other Current Assets		4.6 			(0.7)			(0.8)		
Other Current Liabilities		(13.7)			4.6 			6.4 		
Net Cash Flows from Operating Activities		157.0 			350.3 			330.5 		
							
INVESTING ACTIVITIES							
Construction Expenditures		(337.9)			(291.9)			(240.2)		
Change in Advances to Affiliates, Net		38.8 			(38.8)			— 		
Other Investing Activities		4.0 			2.6 			7.2 		
Net Cash Flows Used for Investing Activities		(295.1)			(328.1)			(233.0)		
							
FINANCING ACTIVITIES							
Issuance of Long-term Debt – Nonaffiliated		— 			349.5 			— 		
Change in Advances from Affiliates, Net		155.4 			(105.5)			(44.1)		
Retirement of Long-term Debt – Nonaffiliated		(13.2)			(250.5)			(0.5)		
	
Principal Payments for Finance Lease Obligations		(3.5)			(3.1)			(3.3)		
Dividends Paid on Common Stock		— 			(11.3)			(50.0)		
Other Financing Activities		0.5 			(1.8)			0.8 		
Net Cash Flows from (Used for) Financing Activities		139.2 			(22.7)			(97.1)		
							
Net Increase (Decrease) in Cash and Cash Equivalents		1.1 			(0.5)			0.4 		
Cash and Cash Equivalents at Beginning of Period		1.5 			2.0 			1.6 		
Cash and Cash Equivalents at End of Period		$	2.6 			$	1.5 			$	2.0 		
							
SUPPLEMENTARY INFORMATION							
Cash Paid for Interest, Net of Capitalized Amounts		$	59.1 			$	61.1 			$	62.0 		
Net Cash Paid (Received) for Income Taxes		(11.8)			22.4 			17.9 		
Noncash Acquisitions Under Finance Leases		3.2 			5.3 			4.3 		
Construction Expenditures Included in Current Liabilities as of December 31,		35.5 			46.0 			33.2 		
Noncash Contribution of Radial Assets from Parent		50.0 			— 			— 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	

214

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

215

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

COMPANY OVERVIEW

As a public utility, SWEPCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 545,000 retail customers in its service territory in northeastern and the panhandle of Texas, northwestern Louisiana and western Arkansas.  SWEPCo consolidates its wholly-owned subsidiary, Southwest Arkansas Utilities Corporation.  SWEPCo also consolidates Sabine Mining Company, a VIE.  SWEPCo sells electric power at wholesale to other utilities, municipalities and electric cooperatives.

216

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales	
						
	Years Ended December 31,	
	2020		2019		2018	
	(in millions of KWhs)	
Retail:						
Residential	5,988 			6,303 			6,564 		
Commercial	5,296 			5,776 			5,911 		
Industrial	4,891 			5,337 			5,391 		
Miscellaneous	79 			80 			79 		
Total Retail	16,254 			17,496 			17,945 		
						
Wholesale	5,838 			6,791 			7,071 		
						
Total KWhs	22,092 			24,287 			25,016 		

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	
						
	Years Ended December 31,	
	2020		2019		2018	
	(in degree days)	
Actual – Heating (a)	862 			1,174 			1,308 		
Normal – Heating (b)	1,181 			1,191 			1,195 		
						
Actual – Cooling (c)	2,165 			2,392 			2,560 		
Normal – Cooling (b)	2,333 			2,321 			2,311 		

(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.

217

2020 Compared to 2019

Reconciliation of Year Ended December 31, 2019 to Year Ended December 31, 2020
Earnings Attributable to SWEPCo Common Shareholder
(in millions)

Year Ended December 31, 2019		$	158.6 		
			
Changes in Gross Margin:			
Retail Margins (a)		(14.9)		
Margins from Off-system Sales		(0.1)		
Transmission Revenues		52.8 		
Other Revenues		(2.4)		
Total Change in Gross Margin		35.4 		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		25.6 		
	
Depreciation and Amortization		(23.6)		
Taxes Other Than Income Taxes		(2.6)		
Interest Income		(0.5)		
Allowance for Equity Funds Used During Construction		0.9 		
Non-Service Cost Components of Net Periodic Benefit Cost		(0.1)		
Interest Expense		0.6 		
Total Change in Expenses and Other		0.3 		
			
Income Tax Expense		(14.1)		
Equity Earnings of Unconsolidated Subsidiary		(0.1)		
Net Income Attributable to Noncontrolling Interest		0.7 		
			
Year Ended December 31, 2020		$	180.8 		

(a)Includes firm wholesale sales to municipals and cooperatives.

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 decreased $15 million primarily due to the following:
•A $30 million decrease in weather-related usage primarily due to a 9% decrease in cooling degree days and a 27% decrease in heating degree days.
•An $11 million decrease in weather-normalized margins primarily in the commercial and industrial classes, partially offset in the residential class.
•An $11 million decrease in weather-normalized wholesale margins, including the loss of a wholesale contract.
•A $10 million decrease due to a 2020 regulatory provision.
These decreases were partially offset by:
•A $45 million increase primarily due to rider increases in all jurisdictions and a base rate revenue increase in Arkansas. This increase was partially offset in other expense items below.
•Transmission Revenues increased $53 million primarily due to the following:
•A $31 million increase as a result of the annual transmission formula rate true-up. This increase was partially offset by an increase in transmission expenses in SPP.
•A $22 million increase due to continued investment in transmission projects.
218

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

•Other Operation and Maintenance expenses decreased $26 million primarily due to the following:
•A $10 million decrease in expenses at various generation plants.
•A $10 million decrease in administrative and general expenses primarily due to an insurance settlement.
•A $9 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs.
•A $6 million decrease in customer-related expenses primarily in energy efficiency programs. This decrease was offset in Retail Margins above.
•A $6 million decrease due to a charitable contribution to the AEP Foundation in 2019.
These decreases were partially offset by:
•A $19 million increase in SPP transmission expenses primarily due to the annual formula rate true-up. This increase was offset in Transmission Revenues above.
•Depreciation and Amortization expenses increased $24 million primarily due to a higher depreciable base and an increase in Arkansas depreciation rates beginning in January 2020. This increase was partially offset in Retail Margins above.
•Income Tax Expense increased $14 million primarily due to an increase in pretax book income and a decrease in Excess ADIT amortization. This decrease of Excess ADIT not subject to normalization requirements amortization was partially offset in Retail Margins above.

219

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Southwestern Electric Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Southwestern Electric Power Company and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of income, of comprehensive income (loss), of changes in equity and of cash flows for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.

Change in Accounting Principle

As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
220

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company’s consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, whether influenced by issuance of regulatory commission orders, passage of new legislation, or changes in the regulatory environment. As of December 31, 2020, there were $405.7 million of deferred costs included in regulatory assets, $247.3 million of which were pending final regulatory approval, and $901.0 million of regulatory liabilities awaiting potential refund or future rate reduction, $313.4 million of which were pending final regulatory determination.

The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and applying guidance contained in rate orders and other relevant evidence; which in turn led to significant audit effort and a high degree of auditor subjectivity in performing procedures and in evaluating audit evidence relating to management’s judgments about the probability of recovery of regulatory assets and refund of regulatory liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s assessment of regulatory proceedings, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management’s assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, including those subject to pending rate cases, also involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, and application of regulatory precedents.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

We have served as the Company's auditor since 2017.
221

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Southwestern Electric Power Company Consolidated (SWEPCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  SWEPCo’s internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of SWEPCo’s internal control over financial reporting as of December 31, 2020.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013).  Based on management’s assessment, management concluded SWEPCo’s internal control over financial reporting was effective as of December 31, 2020.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, SWEPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit SWEPCo to provide only management’s report in this annual report.
222

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
REVENUES							
Electric Generation, Transmission and Distribution		$	1,696.6 			$	1,744.6 			$	1,791.9 		
Sales to AEP Affiliates		41.0 			36.9 			35.1 		
Provision for Refund - Affiliated		(2.0)			(32.0)			(6.7)		
Other Revenues		2.9 			1.4 			1.6 		
TOTAL REVENUES		1,738.5 			1,750.9 			1,821.9 		
							
EXPENSES							
Fuel and Other Consumables Used for Electric Generation		443.5 			472.8 			502.3 		
Purchased Electricity for Resale		161.0 			179.5 			177.1 		
	
Other Operation		338.3 			348.0 			384.2 		
Maintenance		129.7 			145.6 			141.5 		
	
Depreciation and Amortization		272.7 			249.1 			239.5 		
Taxes Other Than Income Taxes		102.8 			100.2 			99.6 		
TOTAL EXPENSES		1,448.0 			1,495.2 			1,544.2 		
							
OPERATING INCOME		290.5 			255.7 			277.7 		
							
Other Income (Expense):							
Interest Income		2.1 			2.6 			5.4 		
Allowance for Equity Funds Used During Construction		7.7 			6.8 			6.0 		
Non-Service Cost Components of Net Periodic Benefit Cost		8.4 			8.5 			8.7 		
Interest Expense		(118.5)			(119.1)			(127.9)		
							
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS		190.2 			154.5 			169.9 		
							
Income Tax Expense (Benefit)		9.4 			(4.7)			20.4 		
Equity Earnings of Unconsolidated Subsidiary		2.9 			3.0 			2.7 		
							
NET INCOME		183.7 			162.2 			152.2 		
							
Net Income Attributable to Noncontrolling Interest		2.9 			3.6 			5.0 		

	

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER		$	180.8 			$	158.6 			$	147.2 		
							
The common stock of SWEPCo is wholly-owned by Parent.	
							
See Notes to Financial Statements of Registrants beginning on page 229.	
223

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2020, 2019 and 2018
 (in millions)

		Years Ended December 31,	
		2020		2019		2018	
Net Income		$	183.7 			$	162.2 			$	152.2 		
							
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES							
Cash Flow Hedges, Net of Tax of $0.4, $0.4 and $1.1 in 2020, 2019 and 2018, Respectively		1.5 			1.5 			4.0 		
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.4), $(0.3) and $(0.4) in 2020, 2019 and 2018, Respectively		(1.5)			(1.1)			(1.4)		
Pension and OPEB Funded Status, Net of Tax of $0.9, $1.0 and $(0.8) in 2020, 2019 and 2018, Respectively		3.2 			3.7 			(3.1)		
							
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		3.2 			4.1 			(0.5)		
							
TOTAL COMPREHENSIVE INCOME		186.9 			166.3 			151.7 		
							
Total Comprehensive Income Attributable to Noncontrolling Interest		2.9 			3.6 			5.0 		
							
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER		$	184.0 			$	162.7 			$	146.7 		
							
See Notes to Financial Statements of Registrants beginning on page 229.	
224

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

	SWEPCo Common Shareholder					
	Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Noncontrolling
Interest		Total	
TOTAL EQUITY – DECEMBER 31, 2017	$	135.7 			$	676.6 			$	1,426.6 			$	(4.0)			$	(0.4)			$	2,234.5 		
												
Common Stock Dividends					(65.0)							(65.0)		
Common Stock Dividends – Nonaffiliated									(4.3)			(4.3)		
ASU 2018-02 Adoption					(0.4)			(0.9)					(1.3)		
	
Net Income					147.2 					5.0 			152.2 		
Other Comprehensive Loss							(0.5)					(0.5)		
	
TOTAL EQUITY – DECEMBER 31, 2018	135.7 			676.6 			1,508.4 			(5.4)			0.3 			2,315.6 		
												
Common Stock Dividends					(37.5)							(37.5)		
Common Stock Dividends – Nonaffiliated									(3.3)			(3.3)		
	
Net Income					158.6 					3.6 			162.2 		
Other Comprehensive Income							4.1 					4.1 		
TOTAL EQUITY – DECEMBER 31, 2019	135.7 			676.6 			1,629.5 			(1.3)			0.6 			2,441.1 		
												
Reverse Common Stock Split (a)	(135.6)			135.6 									— 		
	
Common Stock Dividends – Nonaffiliated									(1.9)			(1.9)		
ASU 2016-03 Adoption					1.6 							1.6 		
Net Income					180.8 					2.9 			183.7 		
Other Comprehensive Income							3.2 					3.2 		
TOTAL EQUITY – DECEMBER 31, 2020	$	0.1 			$	812.2 			$	1,811.9 			$	1.9 			$	1.6 			$	2,627.7 		
												
(a) See Note 14 - Financing Activities for additional information.	
												
See Notes to Financial Statements of Registrants beginning on page 229.	
225

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2020 and 2019
(in millions)

		December 31,	
		2020		2019	
CURRENT ASSETS					
Cash and Cash Equivalents
(December 31, 2020 and 2019 Amounts Include $10.1 and $0, Respectively, Related to Sabine)		$	13.2 			$	1.6 		
Advances to Affiliates		2.1 			2.1 		
Accounts Receivable:					
Customers		27.1 			29.0 		
Affiliated Companies		25.1 			34.5 		
Miscellaneous		12.7 			13.5 		
Allowance for Uncollectible Accounts		— 			(1.7)		
Total Accounts Receivable		64.9 			75.3 		
Fuel
(December 31, 2020 and 2019 Amounts Include $35.2 and $47, Respectively, Related to Sabine)		191.1 			140.1 		
Materials and Supplies
(December 31, 2020 and 2019 Amounts Include $23.3 and $23.1, Respectively, Related to Sabine)		95.8 			94.0 		
Risk Management Assets		3.2 			6.4 		
	
Accrued Tax Benefits		29.9 			7.6 		
Regulatory Asset for Under-Recovered Fuel Costs		2.6 			4.9 		
Prepayments and Other Current Assets		25.2 			22.1 		
TOTAL CURRENT ASSETS		428.0 			354.1 		
					
PROPERTY, PLANT AND EQUIPMENT					
Electric:					
Generation		4,681.4 			4,691.4 		
Transmission		2,165.7 			2,056.5 		
Distribution		2,382.5 			2,270.7 		
Other Property, Plant and Equipment
(December 31, 2020 and 2019 Amounts Include $223.7 and $212.3, Respectively, Related to Sabine)		788.8 			733.4 		
Construction Work in Progress		228.3 			216.9 		
Total Property, Plant and Equipment		10,246.7 			9,968.9 		
Accumulated Depreciation and Amortization
(December 31, 2020 and 2019 Amounts Include $126.5 and $107.5, Respectively, Related to Sabine)		3,158.5 			2,873.7 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		7,088.2 			7,095.2 		
					
OTHER NONCURRENT ASSETS					
Regulatory Assets		403.1 			222.4 		
Deferred Charges and Other Noncurrent Assets		234.8 			160.5 		
TOTAL OTHER NONCURRENT ASSETS		637.9 			382.9 		
					
TOTAL ASSETS		$	8,154.1 			$	7,832.2 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	
226

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2020 and 2019

		December 31,	
		2020		2019	
		(in millions)	
CURRENT LIABILITIES					
Advances from Affiliates		$	124.6 			$	59.9 		
Accounts Payable:					
General		135.9 			138.0 		
Affiliated Companies		43.0 			53.6 		
Short-term Debt – Nonaffiliated		35.0 			18.3 		
Long-term Debt Due Within One Year – Nonaffiliated		106.2 			121.2 		
Risk Management Liabilities		0.7 			1.9 		
Customer Deposits		61.3 			65.0 		
Accrued Taxes		41.0 			41.8 		
Accrued Interest		34.6 			34.6 		
	
Obligations Under Operating Leases		7.9 			6.5 		
	
Other Current Liabilities		173.4 			133.9 		
TOTAL CURRENT LIABILITIES		763.6 			674.7 		
					
NONCURRENT LIABILITIES					
Long-term Debt – Nonaffiliated		2,530.2 			2,534.4 		
Long-term Risk Management Liabilities		1.0 			3.1 		
Deferred Income Taxes		1,017.6 			940.9 		
Regulatory Liabilities and Deferred Investment Tax Credits		863.4 			892.3 		
Asset Retirement Obligations		193.7 			196.7 		
Employee Benefits and Pension Obligations		18.6 			28.1 		
	
Obligations Under Operating Leases		44.1 			34.7 		
Deferred Credits and Other Noncurrent Liabilities		94.2 			86.2 		
TOTAL NONCURRENT LIABILITIES		4,762.8 			4,716.4 		
					
TOTAL LIABILITIES		5,526.4 			5,391.1 		
					
Rate Matters (Notes 4)					
Commitments and Contingencies (Note 6)					
					
EQUITY					
Common Stock – Par Value – $18 Per Share:					
Authorized – 3,680 Shares					
Outstanding – 3,680 Shares		0.1 			135.7 		
Paid-in Capital		812.2 			676.6 		
Retained Earnings		1,811.9 			1,629.5 		
Accumulated Other Comprehensive Income (Loss)		1.9 			(1.3)		
TOTAL COMMON SHAREHOLDER’S EQUITY		2,626.1 			2,440.5 		
					
Noncontrolling Interest		1.6 			0.6 		
					
TOTAL EQUITY		2,627.7 			2,441.1 		
					
TOTAL LIABILITIES AND EQUITY		$	8,154.1 			$	7,832.2 		
					
See Notes to Financial Statements of Registrants beginning on page 229.	
227

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

		Years Ended December 31,	
		2020		2019		2018	
OPERATING ACTIVITIES							
Net Income		$	183.7 			$	162.2 			$	152.2 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:							
Depreciation and Amortization		272.7 			249.1 			239.5 		
Deferred Income Taxes		32.4 			(11.0)			1.2 		
	
Allowance for Equity Funds Used During Construction		(7.7)			(6.8)			(6.0)		
Mark-to-Market of Risk Management Contracts		(0.1)			0.8 			4.0 		
Pension Contributions to Qualified Plan Trust		(8.9)			— 			— 		
Deferred Fuel Over/Under-Recovery, Net		26.3 			16.5 			(2.4)		
Change in Regulatory Assets		(108.4)			3.5 			(0.7)		
Change in Other Noncurrent Assets		16.1 			2.7 			(18.1)		
Change in Other Noncurrent Liabilities		25.2 			2.7 			42.8 		
Changes in Certain Components of Working Capital:							
Accounts Receivable, Net		7.3 			— 			53.5 		
Fuel, Materials and Supplies		(46.4)			(46.1)			3.5 		
Accounts Payable		11.1 			(28.4)			0.9 		
Accrued Taxes, Net		(23.1)			(3.2)			2.3 		
Other Current Assets		(2.8)			(8.9)			15.6 		
Other Current Liabilities		(21.1)			6.7 			16.5 		
Net Cash Flows from Operating Activities		356.3 			339.8 			504.8 		
							
INVESTING ACTIVITIES							
Construction Expenditures		(402.7)			(412.7)			(451.0)		
Change in Advances to Affiliates, Net		— 			81.3 			(81.4)		
	
Proceeds from Sales of Assets		4.4 			0.2 			1.4 		
Other Investing Activities		5.7 			1.0 			2.1 		
Net Cash Flows Used for Investing Activities		(392.6)			(330.2)			(528.9)		
							
FINANCING ACTIVITIES							
Issuance of Long-term Debt – Nonaffiliated		— 			— 			1,065.7 		
	
Change in Short-term Debt – Nonaffiliated		16.7 			18.3 			(22.0)		
Change in Advances from Affiliates, Net		64.7 			59.9 			(118.7)		
Retirement of Long-term Debt – Nonaffiliated		(21.2)			(59.7)			(794.5)		

Principal Payments for Finance Lease Obligations		(10.9)			(11.0)			(11.5)		
Dividends Paid on Common Stock		— 			(37.5)			(65.0)		
Dividends Paid on Common Stock – Nonaffiliated		(1.9)			(3.3)			(4.3)		
	
Other Financing Activities		0.5 			0.8 			(2.7)		
Net Cash Flows from (Used for) Financing Activities		47.9 			(32.5)			47.0 		
							
Net Increase (Decrease) in Cash and Cash Equivalents		11.6 			(22.9)			22.9 		
Cash and Cash Equivalents at Beginning of Period		1.6 			24.5 			1.6 		
Cash and Cash Equivalents at End of Period		$	13.2 			$	1.6 			$	24.5 		
							
SUPPLEMENTARY INFORMATION							
Cash Paid for Interest, Net of Capitalized Amounts		$	110.7 			$	111.1 			$	125.7 		
Net Cash Paid for Income Taxes		4.3 			8.6 			18.8 		
Noncash Acquisitions Under Finance Leases		8.9 			7.4 			3.6 		
Construction Expenditures Included in Current Liabilities as of December 31,		46.0 			69.1 			42.0 		

							
See Notes to Financial Statements of Registrants beginning on page 229.	
228

INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANTS

The notes to 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	
					
Organization and Summary of Significant Accounting Policies		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		230	
New Accounting Standards		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		247	
Comprehensive Income		AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo		248	
Rate Matters		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		256	
Effects of Regulation		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		264	
Commitments, Guarantees and Contingencies		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		282	
Acquisitions, Dispositions and Impairments		AEP, AEP Texas, APCo, I&M, SWEPCo		289	
Benefit Plans		AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo		293	
Business Segments		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		316	
Derivatives and Hedging		AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo		322	
Fair Value Measurements		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		335	
Income Taxes		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		349	
Leases		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		360	
Financing Activities		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		366	
Stock-based Compensation		AEP		377	
Related Party Transactions		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		382	
Variable Interest Entities and Equity Method Investments		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		390	
Property, Plant and Equipment		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		401	
Revenue from Contracts with Customers		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		408	
Goodwill		AEP		417	
Subsequent Events		AEP, AEP Texas, APCo, PSO, SWEPCo		418	
	
229

1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The disclosures in this note apply to all Registrants unless indicated otherwise.

ORGANIZATION

The Registrants engage in the generation, transmission and distribution of electric power.  The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines.  Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.

AEP provides competitive electric and gas supply for residential, commercial and industrial customers in deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier.

The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services.  In addition, AEP operates competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies.  SWEPCo, through consolidated and non-consolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate.  The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act.  The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company.  The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes.  Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system.

The FERC regulates wholesale power markets and wholesale power transactions.  The Registrants’ wholesale power transactions are generally market-based.  Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs.  Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts.  These contracts are generally formula rate mechanisms, which are trued-up to actual costs annually.  

The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis.  The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas.  For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates.  In addition, all OPCo distribution customers paid for certain legacy generation deferral balances that were fully recovered as of December 31, 2019 and continue to pay for certain legacy deferred generation-related costs through PUCO approved riders.  In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by REPs. AEP has one active REP in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind assets, the power from which is marketed and sold in ERCOT. Power from the Oklaunion Power Station was also marketed and sold by these nonregulated subsidiaries in ERCOT prior to its retirement in September 2020.
230

The FERC also regulates the Registrants’ wholesale transmission operations and rates.  Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring.  Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEPTCo’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based.

In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis.

In addition, the FERC regulates the SIA, Operating Agreement, TA and TCA, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement.  The FERC also regulates the PCA. See Note 16 - Related Party Transactions for additional information.

Principles of Consolidation

AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for AEP Texas include the Registrant Subsidiary, its wholly-owned subsidiaries, Transition Funding (consolidated VIEs) and Restoration Funding (a consolidated VIE). The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a consolidated VIE).  The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (consolidated VIEs).  The consolidated statements of cash flows for OPCo include the Registrant Subsidiary and Ohio Phase-in Recovery Funding (a consolidated VIE) for the years ended December 31, 2019 and 2018. In July 2019, the Ohio Phase-in Recovery funding securitization bonds matured. The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a consolidated VIE).  Intercompany items are eliminated in consolidation.  

The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest.  Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income.

AEP, I&M and SWEPCo have ownership interests in generating units that are jointly-owned.  The proportionate share of the operating costs associated with such facilities is included on the income statements and the assets and liabilities are reflected on the balance sheets.  See Note 17 - Variable Interest Entities and Equity Method Investments and Note 18 - Property, Plant and Equipment for additional information. In October 2020, AEP Texas, PSO and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the Oklaunion Power Station site. See Note 7 – Acquisitions, Dispositions and Impairments for additional information.

Accounting for the Effects of Cost-Based Regulation

The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated.  In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
231

Use of Estimates

The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes.  These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits.  The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements.  Actual results could ultimately differ from those estimates.

Cash and Cash Equivalents

Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.

Restricted Cash (Applies to AEP, AEP Texas and APCo)

Restricted Cash primarily includes funds held by trustees for the payment of securitization 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 statement of cash flows:

		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 		

																					
		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 		

Other Temporary Investments (Applies to AEP)

Other Temporary Investments primarily include marketable securities and investments by its protected cell of EIS. These securities have readily determinable fair values and are carried at fair value with changes in fair value recognized in net income.  The cost of securities sold is based on the specific identification or weighted-average cost method. See “Fair Value Measurements of Other Temporary Investments” section of Note 11 for additional information.

Inventory

Fossil fuel inventories are carried at average cost with the exception of AGR, which is carried at the lower of average cost or net realizable value.  Materials and supplies inventories are carried at average cost.

232

Accounts Receivable

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.

Revenue is recognized over time as the performance obligations of delivering energy to customers are satisfied.  To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo.  Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit.  AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables they acquire from affiliated utility subsidiaries. See “Securitized Accounts Receivable – AEP Credit” section of Note 14 for additional information.

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.

Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries)

APCo, I&M, OPCo, PSO and SWEPCo do not have any significant customers that comprise 10% or more of their operating revenues. AEP Texas had significant transactions with REPs which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Accounts Receivable – Customers as of December 31:

																					
Significant Customers of AEP Texas:	 	 					
Reliant Energy, Direct Energy and TXU Energy (a)	 	2020	 	2019	 	2018	
Percentage of Total Revenues	 	46 	%	 	48 	%	 	45 	%	
Percentage of Accounts Receivable – Customers	 	40 	%	 	43 	%	 	35 	%	

(a)In January 2021, NRG Energy, parent company of Reliant Energy, completed a deal to purchase Direct Energy from Centrica.

233

AEPTCo had significant transactions with AEP Subsidiaries which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Total Accounts Receivable as of December 31:

																					
Significant Customers of AEPTCo:							
AEP Subsidiaries		2020	 	2019		2018	
Percentage of Total Revenues		78 	%		79 	%		77 	%	
Percentage of Total Accounts Receivable		78 	%		78 	%		84 	%	

The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuous basis to minimize credit risk.  The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs.  Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.

Renewable Energy Credits (Applies to all Registrants except AEP Texas and AEPTCo)

In regulated jurisdictions, the Registrants record renewable energy credits (RECs) at cost.  For AEP’s competitive generation business, management records RECs at the lower of cost or market.  The Registrants follow the inventory model for these RECs.  RECs expected to be consumed within one year are reported in Materials and Supplies on the balance sheets.  RECs with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of RECs are reported in the Operating Activities section of the statements of cash flows. RECs are consumed to meet applicable state renewable portfolio standards and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income.  The net margin on sales of RECs affects the determination of deferred fuel and REC costs and the amortization of regulatory assets for certain jurisdictions.

Property, Plant and Equipment

Regulated

Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts.  Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation.  The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss.  The equipment in each primary electric plant account is identified as a separate group.  The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received.  These rates and the related lives are subject to periodic review.  Removal costs accrued are typically recorded as regulatory liabilities when the revenue received for removal costs accrued exceeds actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued.

The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.

Nuclear fuel, including nuclear fuel in the fabrication phase, is included in Other Property, Plant and Equipment on the balance sheets.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.”  When it becomes probable that an asset in-service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost
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of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Nonregulated

Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions.  Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals.  Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation.  A gain or loss would be recorded if the retirement is not considered an interim routine replacement.  Removal costs are charged to expense.

Allowance for Funds Used During Construction and Interest Capitalization

For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant.  The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense on the statements of income.  For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments.

Fair Value Measurements of Assets and Liabilities (Applies to all Registrants except AEPTCo)

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly
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correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs.  Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market.  A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s management performs its own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.  

Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities.  They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities.  Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.  Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, private equity, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value.

Deferred Fuel Costs (Applies to all Registrants except AEP Texas and AEPTCo)

The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized.  The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily using the units-of-production method.  In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets.  Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a commission-approved plan to delay refunds or recoveries beyond a one year period.  These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval.  The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions.  On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals.  FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. The Registrants share the majority of their Off-system Sales margins to customers either through an active FAC or other rate mechanisms. Where the FAC or Off-system Sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.

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Revenue Recognition

Regulatory Accounting

The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.  Regulatory assets (deferred expenses or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching revenue with its passage to customers in cost-based regulated rates.

When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets.  Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur.  Examples of new events include the issuance of a regulatory commission order or passage of new legislation.  If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income.

Retail and Wholesale Supply and Delivery of Electricity

The Registrants recognize revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services.  The Registrants recognize such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts.  In accordance with the applicable state commission’s regulatory treatment, PSO and SWEPCo do not include the fuel portion in unbilled revenue, but rather recognize such revenues when billed to customers.

Wholesale transmission revenue is based on FERC-approved formula rate filings made for each calendar year using estimated costs. Revenues initially recognized per the annual rate filing are compared to actual costs, resulting in the subsequent recognition of an over or under-recovered amount, with interest, that is refunded or recovered, respectively, in a future year’s rates. These annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations”, and are recognized by the Registrants in the second quarter of each calendar year following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable - Affiliated Companies or Accounts Payable - Affiliated Companies on the balance sheets. Any portion of the true-ups applicable to third-parties is recorded as Regulatory Assets or Regulatory Liabilities on the balance sheets. See Note 19 - Revenue from Contracts with Customers for additional information.

Gross versus Net Presentation of Certain Electricity Supply and Delivery Activities

Most of the power produced at the generation plants is sold to PJM or SPP.  The Registrants also purchase power from PJM and SPP to supply power to customers.  Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income.  However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales.

Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income.  Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances.  Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income.  All other non-trading derivative purchases are recorded net in revenues.

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In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated.  In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Energy Marketing and Risk Management Activities (Applies to all Registrants except AEPTCo)

The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and on adjacent markets.  These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices.  These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options.  Certain energy marketing and risk management transactions are with RTOs.

The Registrants recognize revenues from marketing and risk management transactions that are not derivatives as the performance obligation of delivering the commodity is satisfied. Expenses from marketing and risk management transactions that are not derivatives are also recognized upon delivery of the commodity.

The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election.  The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances.  In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).  Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate.

Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge).  In the event the Registrants designate a cash flow hedge, the cash flow hedge’s gain or loss is initially recorded as a component of AOCI.  When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. See “Accounting for Cash Flow Hedging Strategies” section of Note 10 for additional information.

Levelization of Nuclear Refueling Outage Costs (Applies to AEP and I&M)

In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over approximately 18 months, beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.

Maintenance

The Registrants expense maintenance costs as incurred.  If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues.  In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.

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Income Taxes and Investment and Production Tax Credits

The Registrants use the liability method of accounting for income taxes.  Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled.

When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost-of-service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.

AEP and subsidiaries apply the deferral methodology for the recognition of ITCs. Deferred ITCs are amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITCs begins when the asset is placed in-service, except where regulatory commissions reflect ITCs in the rate-making process, then amortization begins when the cash tax benefit is recognized. Alternatively, PTCs reduce income tax expense as they are earned. PTCs are earned when electricity is produced.

The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.”  The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense on the statements of income.

Excise Taxes (Applies to all Registrants except AEPTCo)

As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers.  The Registrants do not record these taxes as revenue or expense.

Debt

Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced.  If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates.  Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition.

Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt.  The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations.  The net amortization expense is included in Interest Expense on the statements of income.

Goodwill (Applies to AEP)

When AEP acquires a business, as defined by the accounting guidance for “Business Combinations,” management recognizes all acquired assets and liabilities at their fair value.  To the extent that consideration exceeds the net fair value of the identified assets and liabilities, goodwill is recognized on the balance sheets.  Goodwill is not amortized.  Management tests acquired goodwill at the reporting unit level for impairment at least annually at its estimated fair value. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods.  

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Pension and OPEB Plans (Applies to all Registrants except AEPTCo)

AEP sponsors a qualified pension plan and two unfunded non-qualified pension plans.  Substantially all AEP employees are covered by the qualified plan or both the qualified and a non-qualified pension plan.  AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees.  The Registrant Subsidiaries account for their participation in the AEP sponsored pension and OPEB plans using multiple-employer accounting.  See Note 8 - Benefit Plans for additional information including significant accounting policies associated with the plans.

Investments Held in Trust for Future Liabilities (Applies to all Registrants except AEPTCo)

AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and SNF disposal.  All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations.  The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities.  To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers.  Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate.  Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities.  The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.

Benefit Plans

All benefit plan assets are invested in accordance with each plan’s investment policy.  The investment policy outlines the investment objectives, strategies and target asset allocations by plan.

The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns.  Strategies used include:

•Maintaining a long-term investment horizon.
•Diversifying assets to help control volatility of returns at acceptable levels.
•Managing fees, transaction costs and tax liabilities to maximize investment earnings.
•Using active management of investments where appropriate risk/return opportunities exist.
•Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.
•Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.

The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities.  The current target asset allocations are as follows:

Pension Plan Assets		Target	
Equity		25 	%	
Fixed Income		59 	%	
Other Investments		15 	%	
Cash and Cash Equivalents		1 	%	
			
OPEB Plans Assets		Target	
Equity		49 	%	
Fixed Income		49 	%	
Cash and Cash Equivalents		2 	%	

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The investment policy for each benefit plan contains various investment limitations.  The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies or certain commingled funds).  However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.

For equity investments, the concentration limits are generally as follows:

•No security in excess of 5% of all equities.
•Cash equivalents must be less than 10% of an investment manager’s equity portfolio.
•No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio.
•No securities may be bought or sold on margin or other use of leverage.

For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices.

A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation.  Real estate properties are illiquid, difficult to value and not actively traded.  The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties.  To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification.  Real estate holdings include core, value-added and opportunistic classifications.

A portion of the pension assets is invested in private equity.  Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance.  Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded.  The pension plan uses limited partnerships to invest across the private equity investment spectrum.   The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise.  The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investments.  

AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses.  AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral.  All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested.  The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security.  The securities lending program’s objective is to provide modest incremental income with a limited increase in risk. As of December 31, 2020 and 2019, the fair value of securities on loan as part of the program was $177 million and $246 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2020 and 2019.

Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts.  The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust.  Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid.  Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities.  With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds.  A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges.  The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.

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Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal.  The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities.  The cash funds are valued each business day and provide daily liquidity.

Nuclear Trust Funds (Applies to AEP and I&M)

Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

•Acceptable investments (rated investment grade or above when purchased).
•Maximum percentage invested in a specific type of investment.
•Prohibition of investment in obligations of AEP, I&M or their affiliates.
•Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust funds for each regulatory jurisdiction.  Regulatory approval is required to withdraw decommissioning funds.  These funds are managed by an external investment manager that must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets.  I&M records these securities at fair value.  I&M classifies debt securities in the trust funds as available-for-sale due to their long-term purpose.

Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters.  See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.

Comprehensive Income (Loss) (Applies to all Registrants except AEPTCo)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources.  It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners.  Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

Stock-Based Compensation Plans

As of December 31, 2020, AEP had performance shares and restricted stock units outstanding under the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP).  Upon vesting, all outstanding performance shares and restricted stock units settle in AEP common stock. Performance units awarded prior to 2017 and restricted stock units granted after January 1, 2013 and prior to January 1, 2017 that vested to executive officers
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were settled in cash. During 2019, all of the remaining performance units and restricted stock units that settle in cash were settled. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries.

AEP maintains a variety of tax qualified and non-qualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock.  This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan (SORP), which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors.  AEP career shares are derived from vested performance shares granted to employees under the 2015 LTIP. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares at the closing market price on the dividend payments date. All AEP career shares are settled in shares of AEP common stock after the executive’s service with AEP ends.

Performance shares awarded after January 1, 2017 are classified as temporary equity in the Mezzanine Equity section of the balance sheets until the awards vest. Upon vesting, the performance shares are classified as permanent equity. These awards may be settled in cash upon an employee’s qualifying termination due to a change in control. Because such event is not solely within the control of the company, these awards are classified outside of permanent equity until the awards vest.

AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors.  These stock units become payable in cash to directors after their service ends.

Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense on a straight-line basis.  Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2020, 2019 and 2018 is based on the number of outstanding awards at the end of each period without a reduction for estimated forfeitures. AEP accounts for forfeitures in the period in which they occur.

For the years ended December 31, 2020, 2019 and 2018, compensation cost is included in Net Income for the performance shares, career shares, restricted stock units and the non-employee director’s stock units. Compensation cost may also be capitalized. See Note 15 - Stock-based Compensation for additional information.

Equity Investment in Unconsolidated Entities (Applies to AEP and SWEPCo)

The equity method of accounting is used for equity investments where either AEP or SWEPCo exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings (Loss) of Unconsolidated Subsidiaries on the statements of income. AEP and SWEPCo regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature.

AEP has various significant equity method investments, which include ETT, DHLC and five wind farms acquired in the purchase of Sempra Renewables LLC. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.

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COVID-19

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 reduced demand for energy, particularly from commercial and industrial customers in 2020.  The Registrants have taken steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. 

As of December 31, 2020 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 for the year ended December 31, 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.

Voluntary Retirement Incentive Program

In June 2020, AEP announced a voluntary retirement incentive program. Eligible employees volunteered for retirement from the date of the announcement through July 6, 2020, with most having an effective retirement date of August 1, 2020. Participating employees were eligible to receive up to six months base pay and a medical premium subsidy. Certain participating employees were also eligible to receive a long-term incentive plan grant, with immediate vesting, of AEP common shares. A total of 200 employees participated in the voluntary retirement program. In August 2020, AEP recorded a charge to expense of $13 million primarily related to lump sum salary payments and cash subsidies. AEP also recorded a charge to expense of $5 million related to the incremental Long-Term Incentive Plan grants issued related to this initiative. Approximately 92% of the expense was initially recorded within the AEPSC and then allocated among affiliated entities including the Registrant Subsidiaries. The impact of this program was immaterial on the Registrants’ financial statements as of December 31, 2020.

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 options and awards.

The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:

		Years Ended December 31,	
		2020		2019		2018	
		(in millions, except per-share data)	
				$/share				$/share				$/share	

Earnings Attributable to AEP Common Shareholders		$	2,200.1 					$	1,921.1 					$	1,923.8 				
													
Weighted-Average Number of Basic AEP Common Shares Outstanding		495.7 			$	4.44 			493.7 			$	3.89 			492.8 			$	3.90 		
Weighted-Average Dilutive Effect of Stock-Based Awards		1.5 			(0.02)			1.6 			(0.01)			1.0 			— 		
Weighted-Average Number of Diluted AEP Common Shares Outstanding		497.2 			$	4.42 			495.3 			$	3.88 			493.8 			$	3.90 		

244

Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the years ended December 31, 2020 and 2019, as the dilutive stock price thresholds were not met. See Note 14 - Financing Activities for additional information related to Equity Units.

There were 128 thousand antidilutive shares outstanding as of December 31, 2020. There were no antidilutive shares outstanding as of December 31, 2019 and 2018.

Reclassifications

Certain reclassifications have been made in the 2019 financial statements and notes to conform to the 2020 presentation.

Supplementary Income Statement Information

The following tables provide the components of Depreciation and Amortization for the years ended December 31, 2020, 2019 and 2018:

2020																	
																	
Depreciation and Amortization		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Depreciation and Amortization of Property, Plant and Equipment		$	2,487.5 			$	364.2 			$	249.0 			$	507.8 			$	393.3 			$	275.0 			$	171.9 			$	271.2 		
Amortization of Certain Securitized Assets		171.3 			171.3 			— 			— 			— 			— 			— 			— 		
Amortization of Regulatory Assets and Liabilities		24.0 			(5.7)			— 			(0.3)			18.3 			1.6 			1.6 			1.5 		
Total Depreciation and Amortization		$	2,682.8 			$	529.8 			$	249.0 			$	507.5 			$	411.6 			$	276.6 			$	173.5 			$	272.7 		

																																																			
2019																	
																	
Depreciation and Amortization		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Depreciation and Amortization of Property, Plant and Equipment		$	2,203.7 			$	365.9 			$	176.0 			$	466.5 			$	330.6 			$	229.4 			$	162.5 			$	247.9 		
Amortization of Certain Securitized Assets		280.7 			258.7 			— 			— 			— 			22.0 			— 			— 		
Amortization of Regulatory Assets and Liabilities		30.1 			(2.3)			— 			0.3 			20.0 			(10.5)			7.0 			1.2 		
Total Depreciation and Amortization		$	2,514.5 			$	622.3 			$	176.0 			$	466.8 			$	350.6 			$	240.9 			$	169.5 			$	249.1 		

																																																			
2018																	
																	
Depreciation and Amortization		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Depreciation and Amortization of Property, Plant and Equipment		$	1,965.0 			$	262.2 			$	133.9 			$	428.1 			$	278.9 			$	232.6 			$	155.5 			$	237.0 		
Amortization of Certain Securitized Assets		287.9 			240.0 			— 			— 			— 			47.9 			— 			— 		
Amortization of Regulatory Assets and Liabilities		33.7 			(2.6)			— 			0.3 			14.2 			(20.8)			8.5 			2.5 		
Total Depreciation and Amortization		$	2,286.6 			$	499.6 			$	133.9 			$	428.4 			$	293.1 			$	259.7 			$	164.0 			$	239.5 		

245

Supplementary Cash Flow Information (Applies to AEP)

		Years Ended December 31,	
Cash Flow Information		2020		2019		2018	
		(in millions)	
Cash Paid (Received) for:							
Interest, Net of Capitalized Amounts		$	1,029.1 			$	1,022.5 			$	939.3 		
Income Taxes		(49.1)			6.1 			(24.7)		
Noncash Investing and Financing Activities:							
Acquisitions Under Finance Leases		44.2 			87.5 			55.6 		
Construction Expenditures Included in Current Liabilities as of December 31,		975.4 			1,341.1 			1,120.4 		
Construction Expenditures Included in Noncurrent Liabilities as of December 31,		5.5 			— 			— 		
	
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,		33.4 			0.1 			4.0 		
Noncash Contribution of Assets by Noncontrolling Interest		— 			— 			84.0 		
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage		2.6 			0.3 			2.2 		
Noncontrolling Interest Assumed with Sempra Renewables LLC and Santa Rita East Acquisition		— 			253.4 			— 		
Liabilities Assumed with Sempra Renewable LLC and Santa Rita East Acquisition		— 			32.4 			— 		
Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,		110.6 			47.3 			— 		
246

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 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.

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.

Management adopted ASU 2020-04 and its related implementation guidance effective January 1, 2021. There was no impact to results of operations, financial position or cash flows upon initial adoption. Management is applying the accounting guidance as relevant contract and hedge accounting relationship modifications are made during the course of the reference rate reform transition period, which ends on December 31, 2022. The guidance generally allows for contract modifications solely related to the replacement of the reference rate to be accounted for as a continuation of the existing contract instead of as an extinguishment of the contract, and would therefore, not trigger certain accounting impacts that would otherwise be required. It also allows entities to change certain critical terms of existing hedge accounting relationships that are affected by reference rate reform. These changes would not require de-designating the hedge accounting relationship.

247

3.  COMPREHENSIVE INCOME

The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have any components of other comprehensive income for any period presented in the financial statements.

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2020, 2019 and 2018.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 - Benefit Plans for additional information.

AEP											
											
		Cash Flow Hedges		Pension and OPEB		 	
For the Year Ended December 31, 2020		Commodity		Interest Rate		Amortization of Deferred Costs		Changes in Funded Status		Total	
 		(in millions)	
Balance in AOCI as of December 31, 2019		$	(103.5)			$	(11.5)			$	130.7 			$	(163.4)			$	(147.7)		
Change in Fair Value Recognized in AOCI		(89.2)			(39.9)		(a)	— 			62.7 			(66.4)		
Amount of (Gain) Loss Reclassified from AOCI											
Generation & Marketing Revenues (b)		(0.4)			— 			— 			— 			(0.4)		
Purchased Electricity for Resale (b)		167.6 			— 			— 			— 			167.6 		
Interest Expense (b)		— 			4.9 			— 			— 			4.9 		
Amortization of Prior Service Cost (Credit)		— 			— 			(19.2)			— 			(19.2)		
Amortization of Actuarial (Gains) Losses		— 			— 			10.3 			— 			10.3 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		167.2 			4.9 			(8.9)			— 			163.2 		
Income Tax (Expense) Benefit		35.1 			1.0 			(1.9)			— 			34.2 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		132.1 			3.9 			(7.0)			— 			129.0 		
Net Current Period Other Comprehensive Income (Loss)		42.9 			(36.0)			(7.0)			62.7 			62.6 		
Balance in AOCI as of December 31, 2020		$	(60.6)			$	(47.5)			$	123.7 			$	(100.7)			$	(85.1)		
248

																																	
AEP											
											
 		Cash Flow Hedges		Pension and OPEB		 	
For the Year Ended December 31, 2019		Commodity		Interest Rate		Amortization of Deferred Costs		Changes in Funded Status		Total	
 		(in millions)	
Balance in AOCI as of December 31, 2018		$	(23.0)			$	(12.6)			$	136.3 			$	(221.1)			$	(120.4)		
Change in Fair Value Recognized in AOCI		(127.2)			(0.2)		(a)	— 			57.7 			(69.7)		
Amount of (Gain) Loss Reclassified from AOCI											
Generation & Marketing Revenues (b)		(0.2)			— 			— 			— 			(0.2)		
Purchased Electricity for Resale (b)		59.5 			— 			— 			— 			59.5 		
Interest Expense (b)		— 			1.5 			— 			— 			1.5 		
Amortization of Prior Service Cost (Credit)		— 			— 			(19.2)			— 			(19.2)		
Amortization of Actuarial (Gains) Losses		— 			— 			12.1 			— 			12.1 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		59.3 			1.5 			(7.1)			— 			53.7 		
Income Tax (Expense) Benefit		12.6 			0.2 			(1.5)			— 			11.3 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		46.7 			1.3 			(5.6)			— 			42.4 		
Net Current Period Other Comprehensive Income (Loss)		(80.5)			1.1 			(5.6)			57.7 			(27.3)		

Balance in AOCI as of December 31, 2019		$	(103.5)			$	(11.5)			$	130.7 			$	(163.4)			$	(147.7)		

																																							
 		Cash Flow Hedges		 		Pension and OPEB		 	
For the Year Ended December 31, 2018		Commodity		Interest Rate		Securities
Available for Sale		Amortization of Deferred Costs		Changes in Funded Status		Total	
 		(in millions)	
Balance in AOCI as of December 31, 2017		$	(28.4)			$	(13.0)			$	11.9 			$	141.6 			$	(179.9)			$	(67.8)		
Change in Fair Value Recognized in AOCI		37.3 			2.3 			— 			— 			(33.0)			6.6 		
Amount of (Gain) Loss Reclassified from AOCI													
Generation & Marketing Revenues (b)		(0.1)			— 			— 			— 			— 			(0.1)		
Purchased Electricity for Resale (b)		(32.6)			— 			— 			— 			— 			(32.6)		
Interest Expense (b)		— 			1.1 			— 			— 			— 			1.1 		
Amortization of Prior Service Cost (Credit)		— 			— 			— 			(19.5)			— 			(19.5)		
Amortization of Actuarial (Gains) Losses		— 			— 			— 			12.8 			— 			12.8 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(32.7)			1.1 			— 			(6.7)			— 			(38.3)		
Income Tax (Expense) Benefit		(6.9)			0.3 			— 			(1.4)			— 			(8.0)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(25.8)			0.8 			— 			(5.3)			— 			(30.3)		
Net Current Period Other Comprehensive Income (Loss)		11.5 			3.1 			— 			(5.3)			(33.0)			(23.7)		
ASU 2018-02 Adoption		(6.1)			(2.7)			— 			— 			(8.2)			(17.0)		
ASU 2016-01 Adoption		— 			— 			(11.9)			— 			— 			(11.9)		
Balance in AOCI as of December 31, 2018		$	(23.0)			$	(12.6)			$	— 			$	136.3 			$	(221.1)			$	(120.4)		
249

																											
AEP Texas									
									
				Pension and OPEB			
				Amortization		Changes in			
		Cash Flow Hedge –		of Deferred		Funded			
For the Year Ended December 31, 2020		Interest Rate		Costs		Status		Total	
	(in millions)	
Balance in AOCI as of December 31, 2019		$	(3.4)			$	4.9 			$	(14.3)			$	(12.8)		
Change in Fair Value Recognized in AOCI		0.1 			— 			2.6 			2.7 		
Amount of (Gain) Loss Reclassified from AOCI									

Interest Expense (b)		1.3 			— 			— 			1.3 		
Amortization of Prior Service Cost (Credit)		— 			(0.1)			— 			(0.1)		
Amortization of Actuarial (Gains) Losses		— 			0.3 			— 			0.3 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.3 			0.2 			— 			1.5 		
Income Tax (Expense) Benefit		0.3 			— 			— 			0.3 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.0 			0.2 			— 			1.2 		
Net Current Period Other Comprehensive Income (Loss)		1.1 			0.2 			2.6 			3.9 		
Balance in AOCI as of December 31, 2020		$	(2.3)			$	5.1 			$	(11.7)			$	(8.9)		

																											
				Pension and OPEB			
				Amortization		Changes in			
		Cash Flow Hedge –		of Deferred		Funded			
For the Year Ended December 31, 2019		Interest Rate		Costs		Status		Total	
	(in millions)	
Balance in AOCI as of December 31, 2018		$	(4.4)			$	4.7 			$	(15.4)			$	(15.1)		
Change in Fair Value Recognized in AOCI		— 			— 			1.1 			1.1 		
Amount of (Gain) Loss Reclassified from AOCI									

Interest Expense (b)		1.3 			— 			— 			1.3 		
Amortization of Prior Service Cost (Credit)		— 			(0.1)			— 			(0.1)		
Amortization of Actuarial (Gains) Losses		— 			0.3 			— 			0.3 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.3 			0.2 			— 			1.5 		
Income Tax (Expense) Benefit		0.3 			— 			— 			0.3 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.0 			0.2 			— 			1.2 		
Net Current Period Other Comprehensive Income (Loss)		1.0 			0.2 			1.1 			2.3 		
ASU 2018-02 Adoption		— 			— 			— 			— 		
Balance in AOCI as of December 31, 2019		$	(3.4)			$	4.9 			$	(14.3)			$	(12.8)		

																											
				Pension and OPEB			
				Amortization		Changes in			
		Cash Flow Hedge –		of Deferred		Funded			
For the Year Ended December 31, 2018		Interest Rate		Costs		Status		Total	
	(in millions)	
Balance in AOCI as of December 31, 2017		$	(4.5)			$	4.5 			$	(12.6)			$	(12.6)		
Change in Fair Value Recognized in AOCI		— 			— 			(1.0)			(1.0)		
Amount of (Gain) Loss Reclassified from AOCI									

Interest Expense (b)		1.3 			— 			— 			1.3 		
Amortization of Prior Service Cost (Credit)		— 			(0.1)			— 			(0.1)		
Amortization of Actuarial (Gains) Losses		— 			0.4 			— 			0.4 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.3 			0.3 			— 			1.6 		
Income Tax (Expense) Benefit		0.3 			0.1 			— 			0.4 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.0 			0.2 			— 			1.2 		
Net Current Period Other Comprehensive Income (Loss)		1.0 			0.2 			(1.0)			0.2 		
ASU 2018-02 Adoption		(0.9)			— 			(1.8)			(2.7)		
Balance in AOCI as of December 31, 2018		$	(4.4)			$	4.7 			$	(15.4)			$	(15.1)		
250

																											
APCo									
									
				Pension and OPEB		 	
				Amortization		Changes in			
		Cash Flow Hedge –		of Deferred		Funded			
For the Year Ended December 31, 2020		Interest Rate		Costs		Status		Total	
	(in millions)	
Balance in AOCI as of December 31, 2019		$	0.9 			$	9.2 			$	(5.1)			$	5.0 		
Change in Fair Value Recognized in AOCI		(0.7)			— 			7.7 			7.0 		
Amount of (Gain) Loss Reclassified from AOCI									

Interest Expense (b)		(1.3)			— 			— 			(1.3)		
Amortization of Prior Service Cost (Credit)		— 			(5.3)			— 			(5.3)		
Amortization of Actuarial (Gains) Losses		— 			0.5 			— 			0.5 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.3)			(4.8)			— 			(6.1)		
Income Tax (Expense) Benefit		(0.3)			(1.0)			— 			(1.3)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(1.0)			(3.8)			— 			(4.8)		
Net Current Period Other Comprehensive Income (Loss)		(1.7)			(3.8)			7.7 			2.2 		
Balance in AOCI as of December 31, 2020		$	(0.8)			$	5.4 			$	2.6 			$	7.2 		

																											
				Pension and OPEB			
				Amortization		Changes in			
		Cash Flow Hedges -		of Deferred		Funded			
For the Year Ended December 31, 2019		Interest Rate		Costs		Status		Total	
		(in millions)	
Balance in AOCI as of December 31, 2018		$	1.8 			$	11.7 			$	(18.5)			$	(5.0)		
Change in Fair Value Recognized in AOCI		— 			— 			13.4 			13.4 		
Amount of (Gain) Loss Reclassified from AOCI									

Interest Expense (b)		(1.1)			— 			— 			(1.1)		
Amortization of Prior Service Cost (Credit)		— 			(5.3)			— 			(5.3)		
Amortization of Actuarial (Gains) Losses		— 			2.1 			— 			2.1 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.1)			(3.2)			— 			(4.3)		
Income Tax (Expense) Benefit		(0.2)			(0.7)			— 			(0.9)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.9)			(2.5)			— 			(3.4)		
Net Current Period Other Comprehensive Income (Loss)		(0.9)			(2.5)			13.4 			10.0 		
	
Balance in AOCI as of December 31, 2019		$	0.9 			$	9.2 			$	(5.1)			$	5.0 		

																																	
						Pension and OPEB			
						Amortization		Changes in			
		Cash Flow Hedges		of Deferred		Funded			
For the Year Ended December 31, 2018		Commodity		Interest Rate		Costs		Status		Total	
		(in millions)	
Balance in AOCI as of December 31, 2017		$	— 			$	2.2 			$	14.8 			$	(15.7)			$	1.3 		
Change in Fair Value Recognized in AOCI		(0.7)			— 			— 			(2.6)			(3.3)		
Amount of (Gain) Loss Reclassified from AOCI											
	
Purchased Electricity for Resale (b)		0.9 			— 			— 			— 			0.9 		
Interest Expense (b)		— 			(1.1)			— 			— 			(1.1)		
Amortization of Prior Service Cost (Credit)		— 			— 			(5.2)			— 			(5.2)		
Amortization of Actuarial (Gains) Losses		— 			— 			1.3 			— 			1.3 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.9 			(1.1)			(3.9)			— 			(4.1)		
Income Tax (Expense) Benefit		0.2 			(0.2)			(0.8)			— 			(0.8)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.7 			(0.9)			(3.1)			— 			(3.3)		
Net Current Period Other Comprehensive Income (Loss)		— 			(0.9)			(3.1)			(2.6)			(6.6)		
ASU 2018-02 Adoption		— 			0.5 			— 			(0.2)			0.3 		
Balance in AOCI as of December 31, 2018		$	— 			$	1.8 			$	11.7 			$	(18.5)			$	(5.0)		
251

																											
I&M									
									
				Pension and OPEB			
				Amortization		Changes in			
		Cash Flow Hedge –		of Deferred		Funded			
For the Year Ended December 31, 2020		Interest Rate		Costs		Status		Total	
		(in millions)	
Balance in AOCI as of December 31, 2019		$	(9.9)			$	4.9 			$	(6.6)			$	(11.6)		
Change in Fair Value Recognized in AOCI		— 			— 			3.1 			3.1 		
Amount of (Gain) Loss Reclassified from AOCI									

Interest Expense (b)		2.0 			— 			— 			2.0 		
Amortization of Prior Service Cost (Credit)		— 			(0.8)			— 			(0.8)		
Amortization of Actuarial (Gains) Losses		— 			0.7 			— 			0.7 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		2.0 			(0.1)			— 			1.9 		
Income Tax (Expense) Benefit		0.4 			— 			— 			0.4 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.6 			(0.1)			— 			1.5 		
Net Current Period Other Comprehensive Income (Loss)		1.6 			(0.1)			3.1 			4.6 		
Balance in AOCI as of December 31, 2020		$	(8.3)			$	4.8 			$	(3.5)			$	(7.0)		

																											
				Pension and OPEB			
				Amortization		Changes in			
		Cash Flow Hedge –		of Deferred		Funded			
For the Year Ended December 31, 2019		Interest Rate		Costs		Status		Total	
		(in millions)	
Balance in AOCI as of December 31, 2018		$	(11.5)			$	5.1 			$	(7.4)			$	(13.8)		
Change in Fair Value Recognized in AOCI		— 			— 			0.8 			0.8 		
Amount of (Gain) Loss Reclassified from AOCI									

Interest Expense (b)		2.0 			— 			— 			2.0 		
Amortization of Prior Service Cost (Credit)		— 			(0.8)			— 			(0.8)		
Amortization of Actuarial (Gains) Losses		— 			0.6 			— 			0.6 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		2.0 			(0.2)			— 			1.8 		
Income Tax (Expense) Benefit		0.4 			— 			— 			0.4 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.6 			(0.2)			— 			1.4 		
Net Current Period Other Comprehensive Income (Loss)		1.6 			(0.2)			0.8 			2.2 		
	
Balance in AOCI as of December 31, 2019		$	(9.9)			$	4.9 			$	(6.6)			$	(11.6)		

																											
				Pension and OPEB			
				Amortization		Changes in			
		Cash Flow Hedge –		of Deferred		Funded			
For the Year Ended December 31, 2018		Interest Rate		Costs		Status		Total	
		(in millions)	
Balance in AOCI as of December 31, 2017		$	(10.7)			$	5.1 			$	(6.5)			$	(12.1)		
Change in Fair Value Recognized in AOCI		— 			— 			(0.6)			(0.6)		
Amount of (Gain) Loss Reclassified from AOCI									

Interest Expense (b)		2.0 			— 			— 			2.0 		
Amortization of Prior Service Cost (Credit)		— 			(0.8)			— 			(0.8)		
Amortization of Actuarial (Gains) Losses		— 			0.8 			— 			0.8 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		2.0 			— 			— 			2.0 		
Income Tax (Expense) Benefit		0.4 			— 			— 			0.4 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.6 			— 			— 			1.6 		
Net Current Period Other Comprehensive Income (Loss)		1.6 			— 			(0.6)			1.0 		
ASU 2018-02 Adoption		(2.4)			— 			(0.3)			(2.7)		
Balance in AOCI as of December 31, 2018		$	(11.5)			$	5.1 			$	(7.4)			$	(13.8)		
252

OPCo

	
		Cash Flow Hedge –	
For the Year Ended December 31, 2020		Interest Rate	
		(in millions)	
Balance in AOCI as of December 31, 2019		$	— 		
Change in Fair Value Recognized in AOCI		— 		
Amount of (Gain) Loss Reclassified from AOCI			

Interest Expense (b)		— 		

Reclassifications from AOCI, before Income Tax (Expense) Benefit		— 		
Income Tax (Expense) Benefit		— 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		— 		
Net Current Period Other Comprehensive Income (Loss)		— 		
Balance in AOCI as of December 31, 2020		$	— 		

									

		Cash Flow Hedge –	
For the Year Ended December 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)		(1.3)		

Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.3)		
Income Tax (Expense) Benefit		(0.3)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(1.0)		
Net Current Period Other Comprehensive Income (Loss)		(1.0)		
	
Balance in AOCI as of December 31, 2019		$	— 		

									

		Cash Flow Hedge –	
For the Year Ended December 31, 2018		Interest Rate	
		(in millions)	
Balance in AOCI as of December 31, 2017		$	1.9 		
Change in Fair Value Recognized in AOCI		— 		
Amount of (Gain) Loss Reclassified from AOCI			

Interest Expense (b)		(1.7)		

Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.7)		
Income Tax (Expense) Benefit		(0.4)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(1.3)		
Net Current Period Other Comprehensive Income (Loss)		(1.3)		
ASU 2018-02 Adoption		0.4 		
Balance in AOCI as of December 31, 2018		$	1.0 		
253

PSO

	
	
		Cash Flow Hedge –	
For the Year Ended December 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)		(1.3)		

Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.3)		
Income Tax (Expense) Benefit		(0.3)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(1.0)		
Net Current Period Other Comprehensive Income (Loss)		(1.0)		
Balance in AOCI as of December 31, 2020		$	0.1 		

									

		Cash Flow Hedge –	
For the Year Ended December 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)		(1.3)		

Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.3)		
Income Tax (Expense) Benefit		(0.3)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(1.0)		
Net Current Period Other Comprehensive Income (Loss)		(1.0)		
	
Balance in AOCI as of December 31, 2019		$	1.1 		

									

		Cash Flow Hedge –	
For the Year Ended December 31, 2018		Interest Rate	
		(in millions)	
Balance in AOCI as of December 31, 2017		$	2.6 		
Change in Fair Value Recognized in AOCI		— 		
Amount of (Gain) Loss Reclassified from AOCI			

Interest Expense (b)		(1.3)		

Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.3)		
Income Tax (Expense) Benefit		(0.3)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(1.0)		
Net Current Period Other Comprehensive Income (Loss)		(1.0)		
ASU 2018-02 Adoption		0.5 		
Balance in AOCI as of December 31, 2018		$	2.1 		
254

																											
SWEPCo									
									
				Pension and OPEB			
				Amortization		Changes in			
		Cash Flow Hedge –		of Deferred		Funded			
For the Year Ended December 31, 2020		Interest Rate		Costs		Status		Total	
		(in millions)	
Balance in AOCI as of December 31, 2019		$	(1.8)			$	(1.3)			$	1.8 			$	(1.3)		
Change in Fair Value Recognized in AOCI		— 			— 			3.2 			3.2 		
Amount of (Gain) Loss Reclassified from AOCI									

Interest Expense (b)		1.9 			— 			— 			1.9 		
Amortization of Prior Service Cost (Credit)		— 			(2.0)			— 			(2.0)		
Amortization of Actuarial (Gains) Losses		— 			0.1 			— 			0.1 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.9 			(1.9)			— 			— 		
Income Tax (Expense) Benefit		0.4 			(0.4)			— 			— 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.5 			(1.5)			— 			— 		
Net Current Period Other Comprehensive Income (Loss)		1.5 			(1.5)			3.2 			3.2 		
Balance in AOCI as of December 31, 2020		$	(0.3)			$	(2.8)			$	5.0 			$	1.9 		

																											
				Pension and OPEB			
				Amortization		Changes in			
		Cash Flow Hedge –		of Deferred		Funded			
For the Year Ended December 31, 2019		Interest Rate		Costs		Status		Total	
		(in millions)	
Balance in AOCI as of December 31, 2018		$	(3.3)			$	(0.2)			$	(1.9)			$	(5.4)		
Change in Fair Value Recognized in AOCI		— 			— 			3.7 			3.7 		
Amount of (Gain) Loss Reclassified from AOCI									

Interest Expense (b)		1.9 			— 			— 			1.9 		
Amortization of Prior Service Cost (Credit)		— 			(2.0)			— 			(2.0)		
Amortization of Actuarial (Gains) Losses		— 			0.6 			— 			0.6 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.9 			(1.4)			— 			0.5 		
Income Tax (Expense) Benefit		0.4 			(0.3)			— 			0.1 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.5 			(1.1)			— 			0.4 		
Net Current Period Other Comprehensive Income (Loss)		1.5 			(1.1)			3.7 			4.1 		
	
Balance in AOCI as of December 31, 2019		$	(1.8)			$	(1.3)			$	1.8 			$	(1.3)		

																											
				Pension and OPEB			
				Amortization		Changes in			
		Cash Flow Hedge –		of Deferred		Funded			
For the Year Ended December 31, 2018		Interest Rate		Costs		Status		Total	
		(in millions)	
Balance in AOCI as of December 31, 2017		$	(6.0)			$	1.2 			$	0.8 			$	(4.0)		
Change in Fair Value Recognized in AOCI		2.3 			— 			(3.1)			(0.8)		
Amount of (Gain) Loss Reclassified from AOCI									

Interest Expense (b)		2.1 			— 			— 			2.1 		
Amortization of Prior Service Cost (Credit)		— 			(2.0)			— 			(2.0)		
Amortization of Actuarial (Gains) Losses		— 			0.2 			— 			0.2 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		2.1 			(1.8)			— 			0.3 		
Income Tax (Expense) Benefit		0.4 			(0.4)			— 			— 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.7 			(1.4)			— 			0.3 		
Net Current Period Other Comprehensive Income (Loss)		4.0 			(1.4)			(3.1)			(0.5)		
ASU 2018-02 Adoption		(1.3)			— 			0.4 			(0.9)		
Balance in AOCI as of December 31, 2018		$	(3.3)			$	(0.2)			$	(1.9)			$	(5.4)		

(a)The change in fair value includes $6 million and $4 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC for the years ended December 31, 2020 and December 31, 2019. See “Sempra Renewables LLC” section of Note 17 for additional information.
(b)Amounts reclassified to the referenced line item on the statements of income.
255

4.  RATE MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  The Registrants’ recent significant rate orders and pending rate filings are addressed in this note.

COVID-19 Pandemic

During the first quarter of 2020, AEP’s electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Shortly thereafter, AEP’s state regulators also imposed temporary moratoria on customary disconnection practices. During the third and the fourth quarters of 2020, most state regulators began to lift restrictions on disconnects. As of December 31, 2020, AEP had resumed disconnections in its regulated jurisdictions with the exception of Virginia, Kentucky and Arkansas. Disconnections resumed in Kentucky during January 2021. AEP continues to work with regulators and stakeholders in Virginia and Arkansas and management currently anticipates resuming customary disconnection practices in the first half of 2021. However, this timing could change if there is new legislation or other regulatory directives issued in the future. 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 accounts receivable. The Registrants have worked with their state commissions to achieve deferral authority for incremental expenses incurred due to COVID-19. All of AEP’s regulated jurisdictions have issued COVID-19 orders, granting deferral authority for incremental COVID-19 expenses, with the exception of Kentucky and Tennessee. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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% ROE. The filing included a proposed Income Tax Refund Rider that will refund $21 million annually of Excess ADIT that is primarily not subject to normalization requirements. The rate case also sought a prudence determination on all transmission and distribution capital additions through 2018 included in interim rates from 2008 to December 2019.

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

256

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.

AEP Texas Interim Transmission and Distribution Rates

Through December 31, 2020, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is estimated to be $79 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. AEP Texas is required to file for a comprehensive rate review no later than April 3, 2024.

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, 2020 using 2017, 2018 and 2019 earnings test years (triennial review). Triennial reviews are subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. In November 2018, the Virginia SCC authorized a ROE of 9.42% applicable to APCo base rate earnings for the 2017-2019 triennial period.

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

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

APCo is currently in the process of retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of December 31, 2020 and 2019, APCo had approximately $35 million and $51 million of Virginia jurisdictional AMR meters as well as $73 million and $75 million of Virginia jurisdictional AMI meters recorded on its balance sheets. APCo pursued full recovery of these assets through its Virginia depreciation rates as discussed above.

257

In November 2020, the Virginia SCC issued an order 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). This 9.2% authorized ROE will also be applied to certain APCo rate adjustment clauses. APCo’s earnings for the 2020-2022 triennial review will continue to be 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. Conversely, as defined by Virginia law, APCo is also eligible to defer for future recovery certain environmental and major storm operation and maintenance expenses up to the bottom of APCo’s authorized Virginia 2020-2022 earnings ROE band. The Virginia SCC also disagreed with APCo’s treatment of the retired coal-fired generation assets for regulatory purposes, and instead adopted the Virginia SCC Staff’s recommendation to treat the remaining unrecovered costs of the retired coal-fired generation assets as a regulatory asset to be amortized over 10 years as of the June 2015 retirement date. The Virginia SCC’s adoption of the Staff’s recommended regulatory treatment of the coal-fired generation assets resulted in a net $40 million increase to APCo’s 2020 pretax income. In addition, the Virginia SCC’s order also included: (a) implementation of the Staff-modified APCo 2017 depreciation study effective January 1, 2018 and (b) implementation of the Staff-modified APCo 2019 depreciation study effective January 1, 2020. The adoption of these depreciation studies resulted in an approximate $47 million reduction to APCo’s 2020 pretax income comprised of a $44 million reduction to revenues for amounts recognized in advance of the recording of depreciation expense for the periods January 2018 through October 2020 and a $3 million increase in depreciation expense for the periods November and December 2020. A corresponding regulatory liability was recorded for the $44 million reduction to revenues. The Virginia SCC’s approval of APCo’s 2019 depreciation study included the ongoing depreciation and recovery of APCo’s Virginia AMI/AMR meter balances. In November 2020, APCo filed a notice of appeal with the Virginia Supreme Court.

In December 2020, an intervenor filed a petition at the Virginia SCC requesting reconsideration of: (a) the failure of the Virginia SCC to apply a threshold earnings test to the approved regulatory asset for APCo’s closed coal-fired generation assets, (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 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 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. If the Virginia SCC did not conclude on APCo’s ability to earn a fair return, APCo requested the Virginia SCC provide such a conclusion. In January 2021, as requested by the Virginia SCC, APCo filed briefs related to the petition for reconsideration.

If the Virginia SCC issues an unfavorable ruling related to the intervenor petition, it could reduce future net income and cash flows and impact financial condition.

West Virginia ENEC and Vegetation Management Riders

In June 2020, the WVPSC issued an order directing APCo and WPCo to increase rider rates relating to ENEC and vegetation management by a combined $101 million ($81 million related to APCo) over twelve months beginning September 2020. This increase will be partially offset by a refund of $38 million ($31 million related to APCo) of Excess ADIT that is not subject to normalization requirements over ten months beginning September 2020. These transactions will result in no overall impact to net income.

258

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 December 31, 2020, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $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 required ETT to file for a comprehensive base rate review no later than February 1, 2021. In December 2020, ETT and various intervenors filed a stipulation and settlement agreement with the PUCT. The agreement maintained ETT’s previously allowed ROE and capital structure and includes: (a) an $8 million decrease to the current annual revenue requirement effective February 1, 2021, (b) ETT must make an interim transmission cost of service filing by April 1, 2021, (c) a $2 million line item decrease to the revenue requirement determined in each interim transmission cost of service filing until the filing of the next comprehensive base rate review and (d) no determination of prudence on any transmission investment added since ETT’s last comprehensive base rate review, which would leave the $1.2 billion of cumulative revenues above subject to review in the next comprehensive base rate review. In January 2021, the PUCT approved the stipulation and settlement agreement. As part of the approved agreement, new rates were implemented in February 2021 and ETT is required to file for a comprehensive base rate review no later than February 1, 2023.

I&M Rate Matters (Applies to AEP and I&M)

2019 Indiana Base Rate Case

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

In March 2020, the IURC issued an order approving a phased-in increase in base rates of up to $77 million based upon an ROE of 9.7%. This approved phase-in increase includes: (a) an annual increase in base rates of $44 million effective March 2020 and (b) an annual increase in base rates of up to $77 million, effective January 2021, based on the IURC-approved forecast of December 31, 2020 Indiana jurisdictional electric plant in service. In January 2021, I&M updated its Indiana retail rates with the IURC based on actual December 31, 2020 I&M Indiana jurisdictional electric plant in service, resulting in a $60 million net annual base rate increase when compared to I&M Indiana base rate levels prior to March 2020. The order also approved the majority of I&M’s proposed changes in depreciation as well as 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 negatively impacts I&M’s annual pretax earnings by approximately $20 million starting June 2020.

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KPCo Rate Matters (Applies to AEP)

2020 Kentucky Base Rate Case

In June 2020, KPCo filed a request with the KPSC for a $65 million net annual increase in base rates based upon a proposed 10% ROE with the increase to be implemented no earlier than January 2021. The filing proposes that KPCo would offset the first year of rate increases by refunding Excess ADIT that is not subject to normalization requirements to customers. Additionally, KPCo requested recovery of the previously authorized deferral of $50 million of Rockport Plant UPA expenses and related carrying charges over a 5-year period beginning in December 2022, through an existing purchased power rider.

In January 2021, the KPSC issued an order approving an annual increase in base rates of $52 million based upon an ROE of 9.3% effective with billing cycles mid-January 2021. The order shortened the previously authorized refund period for Excess ADIT that is not subject to normalization requirements being refunded through a rider from 18 years to 3 years. In addition, the order approved recovery of certain annual PJM OATT expenses above/below the corresponding level recovered in base rates through a rider until KPCo’s next base case; however, recovery of these transmission costs will be re-examined by the KPSC in KPCo’s next base case. The KPSC deferred KPCo’s request to authorize a specific recovery period and mechanism for the previously authorized deferral of $50 million of Rockport Plant UPA expenses and related carrying charges to a future proceeding. The order requires KPCo to submit its next base case in June 2023 for rates effective in January 2024.

In February 2021, KPCo filed for rehearing with the KPSC challenging various adjustments that were made in the order and requesting certain clarifications. Also in February 2021, the KPSC issued an order on rehearing that modified the approved annual increase in base rates from $52 million to $53 million and clarified several items, including the timing of the future proceeding to address a specific recovery period and mechanism for the previously authorized deferral of $50 million of Rockport Plant Unit Power Agreement expenses and related carrying charges. The KPSC will initiate a future proceeding to address a specific recovery period and mechanism for the deferral after KPCo makes a written filing identifying the capacity replacement for the Rockport Unit Power Agreement, including the name of the capacity resource and related reasonably anticipated costs.

OPCo Rate Matters (Applies to AEP and OPCo)

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. Additionally, OPCo filed a request with the PUCO for a 60-day temporary delay of the normal rate case proceeding due to the COVID-19 pandemic with rates expected to be effective approximately mid-2021.

In November 2020, 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. A procedural schedule for the case is pending due to ongoing settlement discussions. If any of the requested costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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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 the Texas Supreme Court. In August 2020, the Texas Supreme Court granted SWEPCo’s petition for review and oral arguments were held in December 2020. SWEPCo expects a decision from the Texas Supreme Court in 2021.

As of December 31, 2020, the net book value of Turk Plant was $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.

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% ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a ROE of 9.6%, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in- service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.

As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without
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changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition.

2018 Louisiana Formula Rate Filing

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

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

In October 2018, the LPSC staff issued a recommendation that SWEPCo refund $11 million of excess federal income taxes collected, as a result of Tax Reform, from January 1, 2018 through July 31, 2018. In June 2019, the LPSC staff issued its report which reaffirmed its $11 million refund recommendation. The report also contends that SWEPCo’s requested annual rate increase of $18 million, which was implemented in August 2018, is overstated by $4 million and proposes an annual rate increase of $14 million. Additionally, the report recommends SWEPCo refund the excess over-collections associated with the $4 million difference for the period of August 2018 through the implementation of new rates. In July 2019, the LPSC approved the $11 million refund. In July 2020, the LPSC issued an order approving an unopposed stipulation and settlement agreement for a one-time refund of $6 million over three months beginning in August 2020.

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 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 December 31, 2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $84 million ($82 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $23 million, all of which is related to the Louisiana jurisdiction. 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 December 31, 2020, 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 $2 million. 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 a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. The proposed net annual increase: (a) includes $5 million related to vegetation management to maintain and improve the reliability of its Texas jurisdictional distribution system, (b) requests a $10 million annual depreciation increase and (c) seeks $2 million annually to establish a storm catastrophe reserve. In addition, SWEPCo also requested recovery of the Texas jurisdictional share of the Dolet Hills Power Station of $45 million which is expected to be retired by the end of 2021. Intervenor and staff testimony is scheduled to be filed in March and April 2021, respectively. 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: (a) requests a $32 million annual depreciation increase to recover Louisiana’s share of the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which are expected to be retired early, and (b) includes $10 million annually to recover deferred other operation and maintenance expenses related to Hurricanes Laura and Delta. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

FERC Rate Matters

AFUDC Waiver (Applies to all Registrants except AEP Texas)

In June 2020, FERC granted a temporary waiver providing utilities the option to elect to modify the existing AFUDC rate calculations in response to the COVID-19 pandemic. As a result of the waiver, the AFUDC formula for the 12-month period starting with March 2020 may be calculated using the simple average of the actual historical short-term debt balances for 2019, instead of current period short-term balances. All other aspects of the AFUDC formula remained unchanged. AEP subsidiaries including certain Registrant Subsidiaries elected to apply the waiver in July 2020. The impact upon election was immaterial on the Registrants’ financial statements. In February 2021, FERC issued an order extending the waiver through September 2021.

OKTCo Radial Asset Transfer (Applies to AEP, AEPTCo and PSO)

In August 2020, AEPSC filed a request with FERC, on behalf of PSO and OKTCo, to transfer OKTCo’s interests in its radial assets to PSO. OKTCo had previously constructed radial assets in the PSO service territory and after the radial assets were placed into service, management determined the radial assets were not eligible to be included as part of OKTCo’s SPP OATT formula rates. In October 2020, FERC approved the request and in December 2020, OKTCo completed the transfer of its interest in the radial assets to PSO, through Parent, at net book value. At the transfer date, the net book value of the radial assets were $60 million, before associated tax liabilities. PSO will seek recovery of the radial assets in its next base rate case, which must be filed by October 2021. If PSO does not receive approval to recover the radial assets, it could reduce future net income and cash flows and impact financial condition.

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5.  EFFECTS OF REGULATION

The disclosures in this note apply to all Registrants unless indicated otherwise.

Coal-Fired Generation Plants (Applies to AEP, PSO and SWEPCo)

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

PSO

In September 2020, the Oklaunion Power Station was retired. As of December 31, 2020, PSO has a regulatory asset for accelerated depreciation pending approval recorded on its balance sheet for $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. See “Oklaunion Power Station” section of Note 7 for additional information.

SWEPCo

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 December 31, 2020, SWEPCo has a regulatory asset for plant retirement costs pending approval recorded on its balance sheet for $35 million related to the Louisiana jurisdictional share of Welsh Plant, Unit 2. See “2020 Louisiana Base Rate Case” section of Note 4 for additional information.

Regulated Generating Units to be Retired

PSO

In 2014, PSO received final approval from the EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. In 2016, as part of 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.

SWEPCo

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 retire the 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 Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation.

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The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of December 31, 2020, of generating facilities planned for early retirement:

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		$	198.4 			$	110.4 			$	19.8 		(b)		2026		(c)		$	14.9 		
Dolet Hills Power Station		74.4 			71.2 			24.0 				2021		(d)		60.8 		
Pirkey Power Plant		199.5 			12.2 			38.7 				2023		(e)		13.8 		
Welsh Plant, Units 1 and 3		549.8 			3.6 			57.6 		(f)		2028		(g)		33.3 		

(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with Northeastern Plant, Unit 3, after retirement.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)Dolet Hills Power Station is current being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Arkansas and Texas jurisdictions.
(e)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(f)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with Welsh Plant, Units 1 and 3, after retirement.
(g)Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo)

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. After careful consideration of current economic conditions, and particularly for the benefit of their customers, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. Based on these actions, management revised the estimated useful life of DHLC’s and Oxbow’s assets 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 cease in September 2021. Management also revised the useful life of the Dolet Hills Power Station to 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 cessation of lignite 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 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 fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $131 million as of December 31, 2020. Also, as of December 31, 2020, SWEPCo had a net over-recovered fuel balance of $35 million, which includes fuel burned 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 October 2020, SWEPCo filed a request with the LPSC for recovery of the Louisiana share of these additional fuel costs. SWEPCo’s filing proposes to defer $36 million of fuel costs in 2021 and recover the deferral plus carrying costs over five years beginning in 2022.

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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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 $212 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 $193 million as of December 31, 2020. Also, as of December 31, 2020, SWEPCo had a net over-recovered fuel balance of $35 million, which includes fuel burned 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.
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Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items:

		AEP	
		December 31,		Remaining Recovery Period	
		2020		2019			
Current Regulatory Assets		(in millions)			
Under-recovered Fuel Costs - earns a return		$	41.4 			$	44.7 			1 year	
Under-recovered Fuel Costs - does not earn a return		49.3 			48.2 			1 year	
Total Current Regulatory Assets		$	90.7 			$	92.9 				
							
Noncurrent Regulatory Assets							
Regulatory assets pending final regulatory approval:							
							
Regulatory Assets Currently Earning a Return							
	
Dolet Hills Power Station Accelerated Depreciation		$	71.2 			$	— 				
Kentucky Deferred Purchased Power Expenses		41.3 			30.2 				
Plant Retirement Costs - Unrecovered Plant, Louisiana		35.2 			35.2 				
Oklaunion Power Station Accelerated Depreciation		34.4 			27.4 				

Other Regulatory Assets Pending Final Regulatory Approval		38.6 			0.7 				
Total Regulatory Assets Currently Earning a Return		220.7 			93.5 				
Regulatory Assets Currently Not Earning a Return							
Storm-Related Costs		134.2 			7.2 				
Plant Retirement Costs - Asset Retirement Obligation Costs		25.9 			30.1 				
COVID-19		24.9 			— 				

	
Vegetation Management Program - AEP Texas		3.8 			29.4 				

	
Other Regulatory Assets Pending Final Regulatory Approval		32.7 			21.5 				
Total Regulatory Assets Currently Not Earning a Return		221.5 			88.2 				
							
Total Regulatory Assets Pending Final Regulatory Approval		442.2 			181.7 				
							
Regulatory assets approved for recovery:							
							
Regulatory Assets Currently Earning a Return							
Plant Retirement Costs - Unrecovered Plant (a)		713.1 			690.5 			23 years	
Plant Retirement Costs - Asset Retirement Obligation Costs		107.1 			87.4 			20 years	
Meter Replacement Costs		55.5 			65.4 			7 years	
Ohio Distribution Decoupling		46.6 			31.4 			2 years	
Environmental Control Projects		38.6 			41.0 			20 years	
Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction		34.4 			13.5 			8 years	
Cook Plant Uprate Project		30.2 			32.6 			13 years	
Storm-Related Costs		11.5 			21.3 			2 years	
Advanced Metering System		— 			26.5 				

	

	

	
Other Regulatory Assets Approved for Recovery		94.4 			79.6 			various	
Total Regulatory Assets Currently Earning a Return		1,131.4 			1,089.2 				
Regulatory Assets Currently Not Earning a Return							
Pension and OPEB Funded Status		1,088.6 			1,309.8 			12 years	
Plant Retirement Costs - Asset Retirement Obligation Costs		212.7 			28.8 			22 years	
Unamortized Loss on Reacquired Debt		120.0 			129.0 			28 years	
Unrealized Loss on Forward Commitments		111.3 			106.8 			12 years	
Vegetation Management		67.8 			43.6 			5 years	
Cook Plant Nuclear Refueling Outage Levelization		39.5 			63.8 			2 years	
PJM/SPP Annual Formula Rate True-up		33.0 			7.3 			2 years	
Postemployment Benefits		29.1 			34.2 			3 years	
OVEC Purchased Power		27.4 			1.5 			2 years	
Fuel and Purchased Power Adjustment Rider		24.0 			7.1 			2 years	
Medicare Subsidy		18.6 			23.2 			4 years	

	

	

	

Other Regulatory Assets Approved for Recovery		181.4 			132.8 			various	
Total Regulatory Assets Currently Not Earning a Return		1,953.4 			1,887.9 				
							
Total Regulatory Assets Approved for Recovery		3,084.8 			2,977.1 				
							
Total Noncurrent Regulatory Assets		$	3,527.0 			$	3,158.8 				

(a)Northeastern Plant, Unit 3 is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. See “Regulated Generating Units to be Retired” section above for additional information.
267

																					
		AEP	
		December 31,		Remaining	
		2020		2019		Refund Period	
Current Regulatory Liabilities		(in millions)			
Over-recovered Fuel Costs - pays a return		$	27.6 			$	77.5 			1 year	
Over-recovered Fuel Costs - does not pay a return		25.0 			9.1 			1 year	
Total Current Regulatory Liabilities		$	52.6 			$	86.6 				
							
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits							
Regulatory liabilities pending final regulatory determination:							
							
Regulatory Liabilities Currently Paying a Return							
Other Regulatory Liabilities Pending Final Regulatory Determination		$	2.5 			$	— 				
Total Regulatory Liabilities Currently Paying a Return		2.5 			— 				
Regulatory Liabilities Currently Not Paying a Return							
	
Other Regulatory Liabilities Pending Final Regulatory Determination		1.5 			0.2 				
Total Regulatory Liabilities Currently Not Paying a Return		1.5 			0.2 				
Income Tax Related Regulatory Liabilities (a)							
Excess ADIT Associated with Certain Depreciable Property		291.6 			571.8 				
Excess ADIT that is Not Subject to Rate Normalization Requirements		193.3 			291.0 			(b)	
	
Total Income Tax Related Regulatory Liabilities		484.9 			862.8 				
							
Total Regulatory Liabilities Pending Final Regulatory Determination		488.9 			863.0 				
							
Regulatory liabilities approved for payment:							
							
Regulatory Liabilities Currently Paying a Return							
Asset Removal Costs		3,061.9 			2,876.7 			(c)	
	
Deferred Investment Tax Credits		4.1 			6.2 			33 years	
Ohio Basic Transmission Cost Rider		— 			37.2 				

Other Regulatory Liabilities Approved for Payment		25.2 			14.4 			various	
Total Regulatory Liabilities Currently Paying a Return		3,091.2 			2,934.5 				
Regulatory Liabilities Currently Not Paying a Return							
Excess Nuclear Decommissioning Funding		1,476.6 			1,236.0 			(d)	
Deferred Investment Tax Credits		216.7 			215.3 			34 years	
PJM Transmission Enhancement Refund		56.2 			67.3 			5 years	
Transition and Restoration Charges - Texas		48.2 			50.5 			9 years	
2017-2019 Virginia Triennial Revenue Provision		44.2 			— 			28 years	
Spent Nuclear Fuel		43.1 			43.6 			(d)	
Peak Demand Reduction/Energy Efficiency		26.3 			23.0 			2 years	
Deferred Gain on Sale of Rockport Unit 2		17.9 			27.2 			2 years	
Ohio Enhanced Service Reliability Plan		5.7 			29.7 			2 years	
Virginia Transmission Rate Adjustment Clause		— 			28.1 				

	

Other Regulatory Liabilities Approved for Payment		71.0 			87.7 			various	
Total Regulatory Liabilities Currently Not Paying a Return		2,005.9 			1,808.4 				
Income Tax Related Regulatory Liabilities (a)							
Excess ADIT Associated with Certain Depreciable Property		3,485.7 			3,303.0 			(e)	
Excess ADIT that is Not Subject to Rate Normalization Requirements		714.9 			890.5 			10 years	
Income Taxes Subject to Flow Through		(1,407.9)			(1,341.8)			54 years	
Total Income Tax Related Regulatory Liabilities		2,792.7 			2,851.7 				
							
Total Regulatory Liabilities Approved for Payment		7,889.8 			7,594.6 				
							
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits		$	8,378.7 			$	8,457.6 				

(a)This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform.  The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base.
(b)2020 and 2019 amounts include approximately $173 million and $172 million, respectively, related to AEP Transmission Holdco’s investment in ETT and Transource Energy.  AEP Transmission Holdco expects to amortize the balance commensurate with the return of Excess ADIT to ETT and Transource Energy’s customers.
(c)Relieved as removal costs are incurred.
(d)Relieved when plant is decommissioned.
(e)Refunded using ARAM.

268

																					
		AEP Texas	
		December 31,		Remaining
Recovery
Period	
Regulatory Assets:		2020		2019			
		(in millions)			
Noncurrent Regulatory Assets							
Regulatory assets pending final regulatory approval:							
							
Regulatory Assets Currently Earning a Return							
Advanced Metering System		$	16.3 			$	— 				
	
Total Regulatory Assets Currently Earning a Return		16.3 			— 				
Regulatory Assets Currently Not Earning a Return							
COVID-19		10.5 			— 				
Vegetation Management Program		3.8 			29.4 				
	
Other Regulatory Assets Pending Final Regulatory Approval		2.3 			1.4 				
Total Regulatory Assets Currently Not Earning a Return		16.6 			30.8 				
							
Total Regulatory Assets Pending Final Regulatory Approval		32.9 			30.8 				
							
Regulatory assets approved for recovery:							
							
Regulatory Assets Currently Earning a Return							
Meter Replacement Costs		29.3 			35.2 			6 years	
Advanced Metering System		— 			26.5 				
Total Regulatory Assets Currently Earning a Return		29.3 			61.7 				
Regulatory Assets Currently Not Earning a Return							
Pension and OPEB Funded Status		145.0 			172.0 			12 years	
Vegetation Management Program		22.4 			— 			5 years	
Storm-Related Costs		17.1 			— 			4 years	
Peak Demand Reduction/Energy Efficiency		7.7 			3.5 			2 years	

	

Other Regulatory Assets Approved for Recovery		12.4 			12.6 			various	
Total Regulatory Assets Currently Not Earning a Return		204.6 			188.1 				
							
Total Regulatory Assets Approved for Recovery		233.9 			249.8 				
							
Total Noncurrent Regulatory Assets		$	266.8 			$	280.6 				

269

																					
		AEP Texas	
		December 31,		Remaining
Refund
Period	
Regulatory Liabilities:		2020		2019			
		(in millions)			
Noncurrent Regulatory Liabilities and							
Deferred Investment Tax Credits							
Regulatory liabilities pending final regulatory determination:							
							
Regulatory Liabilities Currently Paying a Return							
Other Regulatory Liabilities Pending Final Regulatory Determination		$	2.5 			$	— 				
Total Regulatory Liabilities Currently Paying a Return		2.5 			— 				
Income Tax Related Regulatory Liabilities (a)							
Excess ADIT Associated with Certain Depreciable Property		— 			274.9 				
Excess ADIT that is Not Subject to Rate Normalization Requirements		(8.2)			87.1 				
	
Total Income Tax Related Regulatory Liabilities		(8.2)			362.0 				
							
Total Regulatory Liabilities Pending Final Regulatory Determination		(5.7)			362.0 				
							
Regulatory liabilities approved for payment:							
							
Regulatory Liabilities Currently Paying a Return							
Asset Removal Costs		718.3 			689.6 			(b)	

Other Regulatory Liabilities Approved for Payment		5.3 			10.1 			various	
Total Regulatory Liabilities Currently Paying a Return		723.6 			699.7 				
Regulatory Liabilities Currently Not Paying a Return							
Transition and Restoration Charges		48.2 			50.5 			9 years	
Deferred Investment Tax Credits		8.5 			9.6 			20 years	
	
Other Regulatory Liabilities Approved for Payment		1.2 			4.8 			various	
Total Regulatory Liabilities Currently Not Paying a Return		57.9 			64.9 				
Income Tax Related Regulatory Liabilities (a)							
Excess ADIT Associated with Certain Depreciable Property		506.0 			236.5 			(c)	
Excess ADIT that is Not Subject to Rate Normalization Requirements		41.7 			— 			1 years	
Income Taxes Subject to Flow Through		(52.7)			(46.2)			28 years	
Total Income Tax Related Regulatory Liabilities		495.0 			190.3 				
							
Total Regulatory Liabilities Approved for Payment		1,276.5 			954.9 				
							
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits		$	1,270.8 			$	1,316.9 				

(a)This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform.  The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base.
(b)Relieved as removal costs are incurred.
(c)Refunded using ARAM.

270

																					
		AEPTCo	
		December 31,		Remaining
Recovery
Period	
Regulatory Assets:		2020		2019			
		(in millions)			
Noncurrent Regulatory Assets							
Regulatory assets approved for recovery:							

	
	
Regulatory Assets Currently Not Earning a Return							
PJM/SPP Annual Formula Rate True-up		$	15.1 			$	4.2 			2 years	
Total Regulatory Assets Approved for Recovery		15.1 			4.2 				
							
Total Noncurrent Regulatory Assets		$	15.1 			$	4.2 				

																					
		AEPTCo	
		December 31,		Remaining
Refund
Period	
Regulatory Liabilities:		2020		2019			
		(in millions)			
Noncurrent Regulatory Liabilities							

	

	

	

	
Regulatory Liabilities Currently Paying a Return							
Asset Removal Costs		$	198.6 			$	141.0 			(b)	

Total Regulatory Liabilities Currently Paying a Return		198.6 			141.0 				
Income Tax Related Regulatory Liabilities (a)							
Excess ADIT Associated with Certain Depreciable Property		531.5 			535.7 			(c)	
Excess ADIT that is Not Subject to Rate Normalization Requirements		(30.6)			(35.4)			8 years	
Income Taxes Subject to Flow Through		(117.7)			(100.4)			38 years	
Total Income Tax Related Regulatory Liabilities		383.2 			399.9 				
							
Total Regulatory Liabilities Approved for Payment		581.8 			540.9 				
							
Total Noncurrent Regulatory Liabilities		$	581.8 			$	540.9 				

(a)This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform.  The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. 
(b)Relieved as removal costs are incurred.
(c)Refunded using ARAM.

271

																					
		APCo	
		December 31,		Remaining
Recovery
Period	
Regulatory Assets:		2020		2019			
		(in millions)			
Current Regulatory Assets							
Under-recovered Fuel Costs, Virginia - earns a return		$	3.3 			$	36.8 			1 year	
Under-recovered Fuel Costs - does not earn a return		2.0 			5.7 			1 year	
Total Current Regulatory Assets		$	5.3 			$	42.5 				
							
Noncurrent Regulatory Assets							
Regulatory assets pending final regulatory approval:							
							
Regulatory Assets Currently Earning a Return							
COVID-19 - Virginia		$	3.7 			$	— 				
Plant Retirement Costs - Materials and Supplies		— 			0.5 				
Total Regulatory Assets Currently Earning a Return		3.7 			0.5 				
Regulatory Assets Currently Not Earning a Return							
Plant Retirement Costs - Asset Retirement Obligation Costs		25.9 			30.1 				
Environmental Expense Deferral - Virginia		9.3 			— 				
	
COVID-19 - West Virginia		1.5 			— 				
Other Regulatory Assets Pending Final Regulatory Approval		3.4 			— 				

	
Total Regulatory Assets Currently Not Earning a Return		40.1 			30.1 				
							
Total Regulatory Assets Pending Final Regulatory Approval		43.8 			30.6 				
							
Regulatory assets approved for recovery:							
							
Regulatory Assets Currently Earning a Return							
Plant Retirement Costs - Unrecovered Plant (a)		122.4 			86.4 			23 years	

	
Other Regulatory Assets Approved for Recovery		1.0 			0.5 			various	
Total Regulatory Assets Currently Earning a Return		123.4 			86.9 				
Regulatory Assets Currently Not Earning a Return							
Plant Retirement Costs - Asset Retirement Obligation Costs		202.7 			— 			15 years	
Pension and OPEB Funded Status		114.4 			160.8 			12 years	
Unamortized Loss on Reacquired Debt		82.1 			85.5 			25 years	
Vegetation Management Program - West Virginia		45.4 			43.6 			2 years	
Virginia Transmission Rate Adjustment Clause		18.8 			— 			2 years	
Peak Demand Reduction/Energy Efficiency		16.8 			19.5 			6 years	
Postemployment Benefits		13.5 			15.9 			3 years	
PJM Annual Formula Rate True-up		12.7 			— 			2 years	

	

	

	

Other Regulatory Assets Approved for Recovery		12.7 			14.4 			various	
Total Regulatory Assets Currently Not Earning a Return		519.1 			339.7 				
							
Total Regulatory Assets Approved for Recovery		642.5 			426.6 				
							
Total Noncurrent Regulatory Assets		$	686.3 			$	457.2 				

(a)December 31, 2020 amount includes Virginia and West Virginia jurisdictions. December 31, 2019 amount includes West Virginia jurisdiction.

272

																					
		APCo	
		December 31,		Remaining
Refund
Period	
Regulatory Liabilities:		2020		2019			
		(in millions)			
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits							

	

	

	
	
Regulatory liabilities approved for payment:							
							
Regulatory Liabilities Currently Paying a Return							
Asset Removal Costs		$	678.9 			$	635.3 			(b)	
Deferred Investment Tax Credits		0.3 			0.5 			33 years	
Total Regulatory Liabilities Currently Paying a Return		679.2 			635.8 				
Regulatory Liabilities Currently Not Paying a Return							
2017-2019 Virginia Triennial Revenue Provision		44.2 			— 			28 years	
PJM Transmission Enhancement Refund		16.3 			19.5 			5 years	

	
Virginia Transmission Rate Adjustment Clause		— 			28.1 				
Other Regulatory Liabilities Approved for Payment		12.3 			18.0 			various	
Total Regulatory Liabilities Currently Not Paying a Return		72.8 			65.6 				
Income Tax Related Regulatory Liabilities (a)							
Excess ADIT Associated with Certain Depreciable Property		690.0 			718.9 			(c)	
Excess ADIT that is Not Subject to Rate Normalization Requirements		139.1 			210.7 			8 years	
Income Taxes Subject to Flow Through		(356.4)			(362.3)			24 years	
Total Income Tax Related Regulatory Liabilities		472.7 			567.3 				
							
Total Regulatory Liabilities Approved for Payment		1,224.7 			1,268.7 				
							
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits		$	1,224.7 			$	1,268.7 				

(a)This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform.  The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base.
(b)Relieved as removal costs are incurred.
(c)Refunded using ARAM.
273

																					
		I&M	
		December 31,		Remaining
Recovery
Period	
Regulatory Assets:		2020		2019			
		(in millions)			
Current Regulatory Assets							
Under-recovered Fuel Costs - earns a return		$	5.4 			$	3.0 			1 year	
	
Total Current Regulatory Assets		$	5.4 			$	3.0 				
							
Noncurrent Regulatory Assets							
Regulatory assets pending final regulatory approval:							
							
Regulatory Assets Currently Earning a Return							
	
Other Regulatory Assets Pending Final Regulatory Approval		$	0.5 			$	— 				
Total Regulatory Assets Currently Earning a Return		0.5 			— 				
Regulatory Assets Currently Not Earning a Return							

	

	
COVID-19		3.8 			— 				
Cook Plant Study Costs		— 			7.6 				
Other Regulatory Assets Pending Final Regulatory Approval		— 			0.1 				
Total Regulatory Assets Currently Not Earning a Return		3.8 			7.7 				
							
Total Regulatory Assets Pending Final Regulatory Approval		4.3 			7.7 				
							
Regulatory assets approved for recovery:							
							
Regulatory Assets Currently Earning a Return							
Plant Retirement Costs - Unrecovered Plant		191.5 			214.9 			8 years	
Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction		34.4 			13.5 			8 years	
Cook Plant Uprate Project		30.2 			32.6 			13 years	
Deferred Cook Plant Life Cycle Management Project Costs		14.1 			15.1 			14 years	
Cook Plant Turbine		11.1 			13.4 			18 years	
Cook Plant Study Costs - Indiana		10.1 			— 			15 years	

Other Regulatory Assets Approved for Recovery		7.0 			6.9 			various	
Total Regulatory Assets Currently Earning a Return		298.4 			296.4 				
Regulatory Assets Currently Not Earning a Return							
Cook Plant Nuclear Refueling Outage Levelization		39.5 			63.8 			2 years	
Pension and OPEB Funded Status		25.7 			67.5 			12 years	
	
Unamortized Loss on Reacquired Debt		15.7 			17.2 			28 years	
Postemployment Benefits		4.9 			7.2 			3 years	

	

	

	

Other Regulatory Assets Approved for Recovery		16.3 			22.3 			various	
Total Regulatory Assets Currently Not Earning a Return		102.1 			178.0 				
							
Total Regulatory Assets Approved for Recovery		400.5 			474.4 				
							
Total Noncurrent Regulatory Assets		$	404.8 			$	482.1 				

274

																					
		I&M	
		December 31,		Remaining
Refund
Period	
Regulatory Liabilities:		2020		2019			
		(in millions)			
Current Regulatory Liabilities							
	
Over-recovered Fuel Costs, Indiana - does not pay a return		$	20.8 			$	6.1 			1 year	
Total Current Regulatory Liabilities		$	20.8 			$	6.1 				
							
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits							

	

	

	
	
Regulatory liabilities approved for payment:							
							
Regulatory Liabilities Currently Paying a Return							
Asset Removal Costs		$	168.2 			$	166.7 			(b)	
Other Regulatory Liabilities Approved for Payment		17.4 			0.3 			various	
Total Regulatory Liabilities Currently Paying a Return		185.6 			167.0 				
Regulatory Liabilities Currently Not Paying a Return							
Excess Nuclear Decommissioning Funding		1,476.6 			1,236.0 			(c)	
	
Spent Nuclear Fuel		43.1 			43.6 			(c)	
Deferred Investment Tax Credits		21.3 			25.8 			19 years	
PJM Costs and Off-system Sales Margin Sharing - Indiana		13.3 			17.0 			2 years	
PJM Transmission Enhancement Refund		9.9 			11.8 			5 years	
Deferred Gain on Sale of Rockport Unit 2		7.2 			10.9 			2 years	

	

	
Other Regulatory Liabilities Approved for Payment		30.1 			24.9 			various	
Total Regulatory Liabilities Currently Not Paying a Return		1,601.5 			1,370.0 				
Income Tax Related Regulatory Liabilities (a)							
Excess ADIT Associated with Certain Depreciable Property		450.6 			470.9 			(d)	
Excess ADIT that is Not Subject to Rate Normalization Requirements		136.2 			184.5 			4 years	
Income Taxes Subject to Flow Through		(332.0)			(301.0)			20 years	
Total Income Tax Related Regulatory Liabilities		254.8 			354.4 				
							
Total Regulatory Liabilities Approved for Payment		2,041.9 			1,891.4 				
							
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits		$	2,041.9 			$	1,891.4 				

(a)This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform.  The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base.
(b)Relieved as removal costs are incurred.
(c)Relieved when plant is decommissioned.
(d)Refunded using ARAM.
275

																					
		OPCo	
		December 31,		Remaining
Recovery
Period	
Regulatory Assets:		2020		2019			
		(in millions)			

	

Noncurrent Regulatory Assets							
Regulatory assets pending final regulatory approval:							

	
Regulatory Assets Currently Not Earning a Return							
COVID-19		$	4.4 			$	— 				
Storm-Related Costs		4.0 			— 				
Other Regulatory Assets Pending Final Regulatory Approval		— 			0.1 				
Total Regulatory Assets Pending Final Regulatory Approval		8.4 			0.1 				
							
Regulatory assets approved for recovery:							
							
Regulatory Assets Currently Earning a Return							
Ohio Distribution Decoupling		46.6 			31.4 			2 years	
	
Ohio Basic Transmission Cost Rider		12.3 			— 			2 years	
	
Other Regulatory Assets Approved for Recovery		1.3 			— 			various	
Total Regulatory Assets Currently Earning a Return		60.2 			31.4 				
Regulatory Assets Currently Not Earning a Return							
Pension and OPEB Funded Status		130.7 			167.3 			12 years	
Unrealized Loss on Forward Commitments		110.0 			103.6 			12 years	
OVEC Purchased Power		27.4 			1.5 			2 years	
Smart Grid Costs		19.2 			13.7 			2 years	
Distribution Investment Rider		7.4 			10.9 			2 years	
Postemployment Benefits		6.7 			7.6 			3 years	

	
Other Regulatory Assets Approved for Recovery		15.8 			15.7 			various	
Total Regulatory Assets Currently Not Earning a Return		317.2 			320.3 				
							
Total Regulatory Assets Approved for Recovery		377.4 			351.7 				
							
Total Noncurrent Regulatory Assets		$	385.8 			$	351.8 				

276

																					
		OPCo	
		December 31,		Remaining
Refund
Period	
		2020		2019			
Regulatory Liabilities:		(in millions)			
							
Current Regulatory Liabilities							
Over-recovered Fuel Costs - does not pay a return		$	3.9 			$	2.8 			1 year	
Total Current Regulatory Liabilities		$	3.9 			$	2.8 				
							
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits							
Regulatory liabilities pending final regulatory determination:							

	
Regulatory Liabilities Currently Not Paying a Return							
Other Regulatory Liabilities Pending Final Regulatory Determination		$	0.2 			$	0.2 				

	

	
	
Total Regulatory Liabilities Pending Final Regulatory Determination		0.2 			0.2 				
							
Regulatory liabilities approved for payment:							
							
Regulatory Liabilities Currently Paying a Return							
Asset Removal Costs		458.4 			446.3 			(b)	
Ohio Basic Transmission Cost Rider		— 			37.2 				
Other Regulatory Liabilities Approved for Payment		— 			1.3 				
Total Regulatory Liabilities Currently Paying a Return		458.4 			484.8 				
Regulatory Liabilities Currently Not Paying a Return							
	
PJM Transmission Enhancement Refund		24.5 			29.4 			5 years	
Peak Demand Reduction/Energy Efficiency		19.9 			19.7 			2 years	
Ohio Enhanced Service Reliability Plan		5.7 			29.7 			2 years	

	

	
Other Regulatory Liabilities Approved for Payment		0.7 			2.9 			various	
Total Regulatory Liabilities Currently Not Paying a Return		50.8 			81.7 				
Income Tax Related Regulatory Liabilities (a)							
Excess ADIT Associated with Certain Depreciable Property		334.6 			341.6 			(c)	
Excess ADIT that is Not Subject to Rate Normalization Requirements		223.9 			252.3 			8 years	
Income Taxes Subject to Flow Through		(62.7)			(69.7)			29 years	
Total Income Tax Related Regulatory Liabilities		495.8 			524.2 				
							
Total Regulatory Liabilities Approved for Payment		1,005.0 			1,090.7 				
							
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits		$	1,005.2 			$	1,090.9 				

(a)This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform.  The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base.
(b)Relieved as removal costs are incurred.
(c)Refunded using ARAM.

277

																					
		PSO	
		December 31,		Remaining
Recovery
Period	
		2020		2019			
Regulatory Assets:		(in millions)			
							
Current Regulatory Assets							
Under-recovered Fuel Costs - earns a return		$	30.1 			$	— 			1 year	
Total Current Regulatory Assets		$	30.1 			$	— 				
							
Noncurrent Regulatory Assets							
Regulatory assets pending final regulatory approval:							
							
Regulatory Assets Currently Earning a Return							
	
Oklaunion Power Station Accelerated Depreciation		$	34.4 			$	27.4 				
	
Total Regulatory Assets Currently Earning a Return		34.4 			27.4 				
Regulatory Assets Currently Not Earning a Return							

Storm-Related Costs		15.8 			7.2 				
COVID-19		0.3 			— 				
	
Total Regulatory Assets Currently Not Earning a Return		16.1 			7.2 				
							
Total Regulatory Assets Pending Final Regulatory Approval		50.5 			34.6 				
							
Regulatory assets approved for recovery:							
							
Regulatory Assets Currently Earning a Return							
Plant Retirement Costs - Unrecovered Plant (a)		180.8 			167.0 			20 years	
Environmental Control Projects		26.5 			27.8 			20 years	
Meter Replacement Costs		26.2 			30.2 			7 years	
Storm-Related Costs		11.5 			21.3 			2 years	
Red Rock Generating Facility		8.2 			8.4 			36 years	
Other Regulatory Assets Approved for Recovery		0.5 			0.6 			various	
Total Regulatory Assets Currently Earning a Return		253.7 			255.3 				
Regulatory Assets Currently Not Earning a Return							
Pension and OPEB Funded Status		52.3 			73.4 			12 years	
Unamortized Loss on Reacquired Debt		6.1 			6.5 			18 years	

	

	
	
Other Regulatory Assets Approved for Recovery		12.4 			5.4 			various	
Total Regulatory Assets Currently Not Earning a Return		70.8 			85.3 				
							
Total Regulatory Assets Approved for Recovery		324.5 			340.6 				
							
Total Noncurrent Regulatory Assets		$	375.0 			$	375.2 				

(a)Northeastern Plant, Unit 3 is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. See “Regulated Generating Units to be Retired” section above for additional information.
278

																					
		PSO	
		December 31,		Remaining
Refund
Period	
		2020		2019			
Regulatory Liabilities:		(in millions)			
							
Current Regulatory Liabilities							
Over-recovered Fuel Costs - pays a return		$	— 			$	63.9 				
Total Current Regulatory Liabilities		$	— 			$	63.9 				
							
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits							

	

	

	
	
Regulatory liabilities approved for payment:							
							
Regulatory Liabilities Currently Paying a Return							
Asset Removal Costs		$	289.9 			$	286.8 			(b)	
Total Regulatory Liabilities Currently Paying a Return		289.9 			286.8 				
Regulatory Liabilities Currently Not Paying a Return							
	
Deferred Investment Tax Credits		51.0 			51.5 			24 years	
	
Other Regulatory Liabilities Approved for Payment		1.3 			4.7 			various	
Total Regulatory Liabilities Currently Not Paying a Return		52.3 			56.2 				
Income Tax Related Regulatory Liabilities (a)							
Excess ADIT Associated with Certain Depreciable Property		397.0 			405.8 			(c)	
Excess ADIT that is Not Subject to Rate Normalization Requirements		71.3 			96.3 			4 years	
Income Taxes Subject to Flow Through		(8.3)			(7.9)			27 years	
Total Income Tax Related Regulatory Liabilities		460.0 			494.2 				
							
Total Regulatory Liabilities Approved for Payment		802.2 			837.2 				
							
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits		$	802.2 			$	837.2 				

(a)This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform.  The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base.
(b)Relieved as removal costs are incurred.
(c)Refunded using ARAM.
279

																					
		SWEPCo	
		December 31,		Remaining
Recovery
Period	
		2020		2019			
Regulatory Assets:		(in millions)			
							
Current Regulatory Assets							
Under-recovered Fuel Costs - earns a return (a)		$	2.6 			$	4.9 			1 year	
Total Current Regulatory Assets		$	2.6 			$	4.9 				
							
Noncurrent Regulatory Assets							
Regulatory assets pending final regulatory approval:							
							
Regulatory Assets Currently Earning a Return							
Dolet Hills Power Station Accelerated Depreciation		$	71.2 			$	— 				
Plant Retirement Costs - Unrecovered Plant, Louisiana		35.2 			35.2 				
Pirkey Power Plant Accelerated Depreciation		12.2 			— 				
Welsh Plant, Units 1 and 3 Accelerated Depreciation		3.6 			— 				
Other Regulatory Assets Pending Final Regulatory Approval		2.2 			0.2 				
Total Regulatory Assets Currently Earning a Return		124.4 			35.4 				
Regulatory Assets Currently Not Earning a Return							
Storm-Related Costs		99.3 			— 				
Asset Retirement Obligation - Louisiana		9.1 			7.2 				

	
Other Regulatory Assets Pending Final Regulatory Approval		14.5 			3.7 				
Total Regulatory Assets Currently Not Earning a Return		122.9 			10.9 				
							
Total Regulatory Assets Pending Final Regulatory Approval		247.3 			46.3 				
							
Regulatory assets approved for recovery:							
							
Regulatory Assets Currently Earning a Return							
Plant Retirement Costs - Unrecovered Plant, Arkansas		14.4 			15.1 			22 years	
Environmental Controls Projects		12.1 			13.2 			12 years	
Other Regulatory Assets Approved for Recovery		7.1 			8.9 			various	
Total Regulatory Assets Currently Earning a Return		33.6 			37.2 				
Regulatory Assets Currently Not Earning a Return							
Pension and OPEB Funded Status		89.1 			102.6 			12 years	
Plant Retirement Costs - Unrecovered Plant, Texas		16.1 			16.6 			21 years	

	

	

Other Regulatory Assets Approved for Recovery		17.0 			19.7 			various	
Total Regulatory Assets Currently Not Earning a Return		122.2 			138.9 				
							
Total Regulatory Assets Approved for Recovery		155.8 			176.1 				
							
Total Noncurrent Regulatory Assets		$	403.1 			$	222.4 				

(a)December 31, 2020 amount includes Louisiana jurisdiction. December 31, 2019 amount includes Arkansas jurisdiction.
280

																					
		SWEPCo	
		December 31,		Remaining
Refund
Period	
		2020		2019			
Regulatory Liabilities:		(in millions)			
							
Current Regulatory Liabilities							
Over-recovered Fuel Costs - pays a return (a)		$	37.6 			$	13.6 			1 year	
Total Current Regulatory Liabilities		$	37.6 			$	13.6 				
							
Noncurrent Regulatory Liabilities and
Deferred Investment Tax Credits							
Regulatory liabilities pending final regulatory determination:							

	
Income Tax Related Regulatory Liabilities (b)							
Excess ADIT Associated with Certain Depreciable Property		$	291.6 			$	297.0 				
Excess ADIT that is Not Subject to Rate Normalization Requirements		21.8 			22.7 				
	
Total Regulatory Liabilities Pending Final Regulatory Determination		313.4 			319.7 				
							
Regulatory liabilities approved for payment:							
							
Regulatory Liabilities Currently Paying a Return							
Asset Removal Costs		470.9 			453.4 			(c)	

Other Regulatory Liabilities Approved for Payment		2.4 			2.8 			various	
Total Regulatory Liabilities Currently Paying a Return		473.3 			456.2 				
Regulatory Liabilities Currently Not Paying a Return							
	
Peak Demand Reduction/Energy Efficiency		5.2 			6.0 			2 years	
Deferred Investment Tax Credits		1.8 			3.1 			10 years	
Other Regulatory Liabilities Approved for Payment		1.2 			1.7 			various	
Total Regulatory Liabilities Currently Not Paying a Return		8.2 			10.8 				
Income Tax Related Regulatory Liabilities (b)							
Excess ADIT Associated with Certain Depreciable Property		332.5 			339.4 			(d)	
Excess ADIT that is Not Subject to Rate Normalization Requirements		11.5 			27.8 			(e)	
Income Taxes Subject to Flow Through		(275.5)			(261.6)			28 years	
Total Income Tax Related Regulatory Liabilities		68.5 			105.6 				
							
Total Regulatory Liabilities Approved for Payment		550.0 			572.6 				
							
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits		$	863.4 			$	892.3 				

(a)December 31, 2020 amount includes Arkansas and Texas jurisdictions. December 31, 2019 amount includes Texas and Louisiana jurisdictions.
(b)This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform.  The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base.
(c)Relieved as removal costs are incurred.
(d)Refunded using ARAM.
(e)Current balance represents revisions to balances for jurisdictions having previously issued orders on treatment for refund, refund period to be addressed in future proceedings.

281

6.  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.

COMMITMENTS (Applies to all Registrants except AEP Texas and AEPTCo)

The AEP System has substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. Certain contracts contain penalty provisions for early termination.

In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2020:

Contractual Commitments - AEP		Less Than
1 Year		2-3 Years		4-5 Years		After
5 Years		Total	
		(in millions)	
Fuel Purchase Contracts (a)		$	763.9 			$	715.1 			$	212.9 			$	381.5 			$	2,073.4 		
Energy and Capacity Purchase Contracts		211.6 			291.8 			277.0 			928.5 			1,708.9 		
Total		$	975.5 			$	1,006.9 			$	489.9 			$	1,310.0 			$	3,782.3 		

																																	
Contractual Commitments - APCo		Less Than
1 Year		2-3 Years		4-5 Years		After
5 Years		Total	
		(in millions)	
Fuel Purchase Contracts (a)		$	362.8 			$	217.6 			$	11.6 			$	16.3 			$	608.3 		
Energy and Capacity Purchase Contracts		35.5 			72.5 			73.9 			230.2 			412.1 		
Total		$	398.3 			$	290.1 			$	85.5 			$	246.5 			$	1,020.4 		

																																	
Contractual Commitments - I&M		Less Than
1 Year		2-3 Years		4-5 Years		After
5 Years		Total	
		(in millions)	
Fuel Purchase Contracts (a)		$	157.7 			$	278.9 			$	189.3 			$	332.7 			$	958.6 		
Energy and Capacity Purchase Contracts		165.2 			196.7 			60.9 			254.6 			677.4 		
Total		$	322.9 			$	475.6 			$	250.2 			$	587.3 			$	1,636.0 		

																																	
Contractual Commitments - OPCo		Less Than
1 Year		2-3 Years		4-5 Years		After
5 Years		Total	
		(in millions)	
Energy and Capacity Purchase Contracts		$	28.8 			$	58.2 			$	58.1 			$	263.3 			$	408.4 		
	
282

																																	
Contractual Commitments - PSO		Less Than
1 Year		2-3 Years		4-5 Years		After
5 Years		Total	
		(in millions)	
Fuel Purchase Contracts (a)		$	25.3 			$	36.2 			$	— 			$	— 			$	61.5 		
Energy and Capacity Purchase Contracts		89.6 			77.4 			66.8 			160.0 			393.8 		
Total		$	114.9 			$	113.6 			$	66.8 			$	160.0 			$	455.3 		

																																	
Contractual Commitments - SWEPCo		Less Than
1 Year		2-3 Years		4-5 Years		After
5 Years		Total	
		(in millions)	
Fuel Purchase Contracts (a)		$	68.5 			$	39.2 			$	— 			$	— 			$	107.7 		
Energy and Capacity Purchase Contracts		8.3 			8.4 			8.4 			4.2 			29.3 		
Total		$	76.8 			$	47.6 			$	8.4 			$	4.2 			$	137.0 		

(a)Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.

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)

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 revolving credit facility due in June 2022, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of December 31, 2020, no letters of credit were issued under the revolving credit facility.

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 million.  The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2020 were as follows:

Company		Amount		Maturity	
		(in millions)			
AEP		$	179.8 			January 2021 to December 2021	
AEP Texas		2.2 			July 2021	

Guarantees of Equity Method Investees (Applies to AEP)

In April 2019, AEP acquired Sempra Renewables LLC. The transaction resulted in the acquisition of 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 December 31, 2020, 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 $31 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 liability is based upon assessments of the credit quality and default probabilities of the respective PPA counterparties. See “Acquisitions” section of Note 7 for additional information.
283

Indemnifications and Other Guarantees

Contracts

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 December 31, 2020, 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.

Lease Obligations

Certain Registrants lease equipment under master lease agreements.  See “Master Lease Agreements” and “AEPRO Boat and Barge Leases” sections of Note 13 for additional information.

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.

Superfund addresses clean-up of hazardous substances that are released to the environment.  The Federal EPA administers the clean-up programs.  Several states enacted similar laws.  As of December 31, 2020, APCo, OPCo and SWEPCo are named as a Potentially Responsible Party (PRP) for one, three and one sites, respectively, by the Federal EPA for which alleged liability is unresolved.  There are 11 additional sites for which APCo, I&M, KPCo, OPCo and SWEPCo received information requests which could lead to PRP designation.  I&M has also been named potentially liable at three sites under state law. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.  Liability has been resolved for a number of sites with no significant effect on net income.

Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability.  Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often non-hazardous.  Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises.  As of December 31, 2020, management’s estimates do not anticipate material clean-up costs for identified Superfund sites.
284

Virginia House Bill 443 (Applies to AEP and APCo)

In March 2020, Virginia’s Governor signed House Bill 443 (HB 443), effective July 2020, requiring APCo to close certain ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material.  As a result, in June 2020, APCo recorded a $199 million revision to increase estimated Glen Lyn Station ash disposal ARO liabilities.  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 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. APCo will submit filings with the Virginia SCC and the WVPSC requesting recovery of the respective Virginia and West Virginia jurisdictional shares of these Glen Lyn Station ARO costs. As of December 31, 2020, APCo has not yet incurred any incremental costs associated with the removal of coal combustion material at the Glen Lyn Station.

NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M)

I&M owns and operates the two-unit 2,288 MW Cook Plant under licenses granted by the NRC.  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.

Decommissioning and Low-Level Waste Accumulation Disposal

The costs to decommission a nuclear plant are affected by NRC regulations and the SNF disposal program.  Decommissioning costs are accrued over the service life of Cook Plant.  The most recent decommissioning cost study was performed in 2018.  According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste was $2 billion in 2018 non-discounted dollars, with additional ongoing costs of $6 million per year for post decommissioning storage of SNF and an eventual cost of $37 million for the subsequent decommissioning of the SNF storage facility, also in 2018 non-discounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates.  The amounts recovered in rates were $4 million, $7 million and $8 million for the years ended December 31, 2020, 2019 and 2018, respectively.  Decommissioning costs recovered from customers are deposited in external trusts.

As of December 31, 2020 and 2019, the total decommissioning trust fund balances were $3 billion and $2.7 billion, respectively.  Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from customers.  The decommissioning costs (including unrealized gains and losses, interest and trust funds expenses) increase or decrease the recorded liability.

I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant.  However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.

285

Spent Nuclear Fuel Disposal

The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal.  A fee of one-mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the DOE through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to $0. As of December 31, 2020 and 2019, fees and related interest of $281 million and $280 million, respectively, for fuel consumed prior to April 7, 1983 were recorded as Long-term Debt and funds collected from customers along with related earnings totaling $324 million and $323 million, respectively, to pay the fee were recorded as part of Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.  I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.

In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delay in accepting SNF for permanent storage.  Under the settlement agreement, I&M received $24 million, $8 million and $11 million in 2020, 2019 and 2018, respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2022.  The proceeds reduced costs for dry cask storage.  As of December 31, 2020 and 2019, I&M deferred $14 million and $24 million, respectively, in Prepayments and Other Current Assets and $1 million and $1 million, respectively, in Deferred Charges and Other Noncurrent Assets on the balance sheets for dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for additional information.

Nuclear Insurance

I&M carries nuclear property insurance of $2.7 billion to cover an incident at Cook Plant including coverage for decontamination and stabilization, as well as premature decommissioning caused by an extraordinary incident.  Insurance coverage for a nonnuclear property incident at Cook Plant is $500 million.  Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage.  I&M utilizes industry mutual insurers for the placement of this insurance coverage.  Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $42 million for I&M, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses.

The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident of $13.8 billion and applies to any incident at a licensed reactor in the U.S.  Commercially available insurance, which must be carried for each licensed reactor, provides $450 million of coverage.  In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $275 million per nuclear incident on Cook Plant’s reactors payable in annual installments of $41 million.  The number of incidents for which payments could be required is not limited.

In the event of an incident of a catastrophic nature, I&M is covered for public nuclear liability for the first $450 million through commercially available insurance.  The next level of liability coverage of up to $13.3 billion would be covered by claim premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through a rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.

286

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles.  The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions.  Covered property generally includes power plants, substations, facilities and inventories.  Excluded property generally includes transmission and distribution lines, poles and towers.  The insurance programs also generally provide coverage against loss arising from certain claims made by third-parties and are in excess of retentions absorbed by the Registrants.  Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section above for additional information.

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant.  Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation (Applies to AEP and I&M)

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.

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.

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.

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. The district court’s stay of the lease litigation expired in August 2020. Upon expiration of the stay, plaintiffs filed a motion for partial summary judgment, 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 judgement was filed in October 2020. At the parties’ request, the district court stayed the case until February 16, 2021 to provide the parties an opportunity to resolve the case, and the court has since extended the stay until April 26, 2021.
287

Management will continue to defend against the claims and believes its financial statements appropriately reflect the potential outcome of the pending litigation. The ultimate outcome of the pending litigation could reduce future net income and cash flows and impact financial condition.

Patent Infringement Complaint

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 alleges that the AEP Defendants infringed two patents owned by the plaintiffs by using specific processes for mercury control at certain coal-fired generating stations. The complaint was resolved in December 2020 and did not have a material impact on net income, cash flows or financial condition.

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: (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, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act 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. The denial of those claims was appealed to the AEP System Retirement Plan Appeal 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 is reasonably possible of occurring.

Litigation Related to Ohio House Bill 6 (Applies to AEP and OPCo)

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 complaint alleges misrepresentations or omissions by AEP regarding: (a) its alleged participation in public corruption with respect to the passage of Ohio House Bill 6, (b) its regulatory, legislative and lobbying activities in Ohio and (c) its clean energy strategy. 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. The 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 complaints assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets and (c) unjust enrichment 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.
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7.  ACQUISITIONS, DISPOSITIONS AND IMPAIRMENTS

The disclosures in this note apply to AEP unless indicated otherwise.

ACQUISITIONS

2020

Santa Rita East (Generation & Marketing Segment)

In November 2020, AEP acquired an additional 10% interest in Santa Rita East for approximately $44 million resulting in AEP having a total interest of 85%. The acquisition of the incremental ownership interest was accounted for as an equity transaction in accordance with the accounting guidance for "Consolidation" and reduced Noncontrolling Interests on the balance sheets by approximately $44 million. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.

Desert Sky Wind Farm and Trent Wind Farm (Generation & Marketing Segment)

In August 2020, AEP exercised its call right which required the nonaffiliated member of Desert Sky Wind Farm LLC and Trent Wind Farm LLC (collectively the LLCs) to sell its noncontrolling interest to AEP. The exercise price for the call right was determined using a discounted cash flow model with agreed input assumptions as well as updates to certain assumptions reasonably expected based on the actual results of the LLCs. As a result, the LLCs are wholly-owned by AEP and management has concluded that the LLCs are no longer VIEs. AEP paid $57 million in cash, derecognized $63 million of Redeemable Noncontrolling Interest within Mezzanine Equity and recorded an increase of $6 million of Paid-In Capital on the balance sheets. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.

2019

Sempra Renewables LLC (Generation & Marketing Segment)

In April 2019, AEP acquired Sempra Renewables LLC 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 to grow its renewable generation portfolio and to diversify generation resources. AEP paid $580 million in cash and acquired a 50% ownership interest in five non-consolidated joint ventures with net assets valued at $404 million as of the acquisition date (which includes $364 million of existing debt obligations). Additionally, the transaction included the acquisition of two tax equity partnerships and the associated recognition of noncontrolling tax equity interest of $135 million.

Purchase Price Allocation of Sempra Renewables LLC at Acquisition Date - April 22nd, 2019	
Assets:		Liabilities and Equity:		Net Purchase Price	
(in millions)	
Current Assets	$	8.8 			Current Liabilities	$	12.9 				
Property, Plant and Equipment	238.1 			Asset Retirement Obligations	5.7 				
Investment in Joint Ventures	404.0 			Total Liabilities	18.6 				
Other Noncurrent Assets	82.9 			Noncontrolling Interest	134.8 				
Total Assets	$	733.8 			Liabilities and Noncontrolling Interest	$	153.4 			$	580.4 		

Management allocated the purchase price based upon the relative fair value of the assets acquired and noncontrolling interests assumed. The fair value of the primary assets acquired and the noncontrolling interests assumed was determined using a discounted cash flow method under the income approach. The key input assumptions utilized in the determination of the fair value of these assets were the pricing and terms of the existing PPAs, forecasted market power prices, expected wind farm net capacity and discount rates reflecting risk inherent in the future cash flows and future power prices. Estimating forecasted market power prices involved determining the
289

cost of constructing and operating a new wind plant over an assumed life in the same geographic region as of the acquisition date using third-party market participant assumptions. The expected wind farm net capacity was developed by evaluating each wind farm’s historical and expected generation against historical generation of comparable wind farms in the same locations. Discount rates were evaluated by considering the cost of capital of comparable businesses. Additional key input assumptions for the fair value of the noncontrolling interests include the terms of the limited liability company agreements that dictate the sharing of the tax attributes and cash flows associated with the tax equity partnerships.

Upon closing of the purchase, Sempra Renewables LLC was legally renamed AEP Wind Holdings LLC. AEP Wind Holdings LLC develops, owns and operates, or holds interests in, wind generation facilities in the United States. The operating 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. The PPAs with I&M, OPCo and SWEPCo were executed prior to the acquisition of the wind farms and will be accounted for in accordance with the accounting guidance for “Related Parties.” See “Sempra Renewables LLC PPAs” section of Note 16 for additional information.

The acquired business contributed revenues and net income to AEP that were not material for the period April 22, 2019 to December 31, 2019. The pro-forma revenue and net income related to the acquisition of Sempra Renewables LLC were not material for the year ended December 31, 2019.

See Note 17 - Variable Interest Entities and Equity Method Investments for additional information related to the purchased wind farms.

Santa Rita East (Generation & Marketing Segment)

In July 2019, AEP acquired a 75% interest, or 227 MWs, in Santa Rita East for approximately $356 million. In accordance with the accounting guidance for “Business Combinations,” management determined that the acquisition of Santa Rita East represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Santa Rita East is a VIE. As a result, to account for the initial consolidation of Santa Rita East, 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 noncontrolling interest assumed was determined using the market approach.  The key input assumptions were the transaction price paid for AEP’s interest in Santa Rita East and recent third-party market transactions for similar wind farms. See “Santa Rita East” section of Note 17 for additional information.

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DISPOSITIONS

2020

Conesville Plant (Generation & Marketing Segment)

In June 2020, AEP and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the merchant Conesville Plant site. The purchaser took ownership of the assets and assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Conesville Plant site. In consideration of the transfer of the acquired assets to the purchaser and the purchaser’s assumption of liabilities, AEP will pay a total of approximately $98 million over three years, derecognized $106 million in ARO and recorded an immaterial gain on the transaction which is recorded in Other Operation on the statements of income. AEP paid approximately $26 million at closing in June 2020 and made an additional payment of $10 million in the fourth quarter of 2020. AEP will make additional payments as detailed in the table below:

			2021		2022	
		(in millions)	
First Quarter			$	9.6 			$	9.6 		
Second Quarter			9.6 			9.6 		
Third Quarter			9.6 			5.2 		
Fourth Quarter			9.6 			— 		
Total			$	38.4 			$	24.4 		

Oklaunion Power Station (Transmission and Distribution Segment and Vertically Integrated Utilities Segment) (Applies to AEP, AEP Texas and PSO)

In October 2020, AEP Texas, PSO and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the Oklaunion Power Station site. The purchaser took ownership of the assets and assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Oklaunion Power Station site. The sale had an immaterial impact on the financial statements in the fourth quarter of 2020.

IMPAIRMENTS

2019

2019 Texas Base Rate Case (Transmission and Distribution Segment) (Applies to AEP and AEP Texas)

In December 2019, AEP Texas recorded a pretax impairment of $33 million in Asset Impairments and Other Related Charges on the statements of income due to regulatory disallowances in the 2019 Texas Base Rate Case. See “2019 Texas Base Rate Case” section of Note 4 for additional information.

Virginia Jurisdictional Book Value of Retired Coal-Fired Plants (Vertically Integrated Utilities Segment) (Applies to AEP and APCo)

In December 2019, based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million in Asset Impairments and Other Related Charges on the statements of income related to its previously retired coal-fired generation.  As a result, management deemed these costs to be substantially recovered by APCo during the triennial review period. See “2017-2019 Virginia Triennial Review” section of Note 4 for additional information.

291

Merchant Generating Assets (Generation & Marketing Segment)

Due to a significant increase in the asset retirement costs recorded in December 2019 for the Ash Pond Complex at Conesville Plant, AEP performed an impairment analysis on Conesville Plant in accordance with accounting guidance for impairments of long-lived assets. AEP performed step one and step two of the impairment analysis using a cash flow model for the estimated useful life of Conesville Plant based upon energy and capacity price curves, which were developed internally with both observable Level 2 third-party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses. The step two analysis resulted in a fair value determination for Conesville Plant of $0 and AEP recorded a $31 million pretax impairment, equal to the net book value of the plant, in Asset Impairments and Other Related Charges on AEP’s statements of income in the fourth quarter of 2019.

2018

Other Assets (Corporate and Other) (Vertically Integrated Utilities Segment) (Applies to AEP and APCo)

In the first quarter of 2018, AEP was notified by an equity investee that it had ceased operations. AEP recorded a pretax impairment of $21 million in Asset Impairments and Other Related Charges on the statements of income related to the equity investment and related assets. The impairment also had an immaterial impact to APCo.

Merchant Generating Assets (Generation & Marketing Segment)

A project to reconstruct a defective dam structure at Racine began in the first quarter of 2017 and reconstruction activities continued throughout 2018. AEP initially impaired Racine in 2017 as discussed in the “2017 Merchant Generating Assets” section of the Acquisitions, Dispositions and Impairments Note within the 2019 Annual Report.

Through the third quarter of 2018, the Racine reconstruction project had accumulated new capital expenditures of $35 million. Due to a significant increase in estimated costs to complete the reconstruction project, an impairment analysis was performed. AEP performed step one of the impairment analysis using undiscounted cash flows for the estimated useful life of Racine based upon energy and capacity price curves, which were developed internally with observable Level 2 third-party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. AEP performed step two of the impairment analysis on Racine using a ten-year discounted cash flow model based upon similar forecasted information used in the step one test. The step two analysis resulted in a determination that the fair value of Racine in its condition as of September 30, 2018 was $0. As a result, AEP recorded a pretax impairment of $35 million in Other Operation on the statements of income in the third quarter of 2018. In October 2018, AEP received authorization from the FERC to restart generation at Racine and generation resumed in November 2018. Reconstruction activities at Racine were completed in 2020.

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8.  BENEFIT PLANS

The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1.

AEP sponsors a qualified pension plan and two unfunded non-qualified pension plans.  Substantially all AEP employees are covered by the qualified plan or both the qualified and a non-qualified pension plan.  AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees.

Due to the Registrant Subsidiaries’ participation in AEP’s benefit plans, the assumptions used by the actuary, with the exception of the rate of compensation increase, and the accounting for the plans by each subsidiary are the same.  This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant.

The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets.  Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance.  The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost.  The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for rate-making purposes are deferred for future recovery.  The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions used in the measurement of the Registrants’ benefit obligations are shown in the following tables:

		Pension Plans		OPEB	
		December 31,	
Assumption		2020		2019		2020		2019	
Discount Rate		2.50 	%		3.25 	%		2.55 	%		3.30 	%	
Interest Crediting Rate		4.00 	%		4.00 	%		NA		NA	

NA    Not applicable.

		Pension Plans	
		December 31,	
Assumption – Rate of Compensation Increase (a)		2020		2019	
AEP		5.00 	%		4.95 	%	
AEP Texas		5.05 	%		5.00 	%	
APCo		4.85 	%		4.80 	%	
I&M		5.00 	%		4.95 	%	
OPCo		5.25 	%		5.15 	%	
PSO		5.05 	%		5.05 	%	
SWEPCo		4.90 	%		4.90 	%	

(a)Rates are for base pay only.  In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
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A duration-based method is used to determine the discount rate for the plans.  A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.  The discount rate is the same for each Registrant.

For 2020, the rate of compensation increase assumed varies with the age of the employee, ranging from 3% per year to 11.5% per year, with the average increase shown in the table above.  The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan.

Actuarial Assumptions for Net Periodic Benefit Costs

The weighted-average assumptions used in the measurement of each Registrants’ benefit costs are shown in the following tables:

		Pension Plans		OPEB	
		Year Ended December 31,	
Assumption		2020		2019		2018		2020		2019		2018	
Discount Rate		3.25 	%		4.30 	%		3.65 	%		3.30 	%		4.30 	%		3.60 	%	
Interest Crediting Rate		4.00 	%		4.00 	%		4.00 	%		NA		NA		NA	
Expected Return on Plan Assets		5.75 	%		6.25 	%		6.00 	%		5.50 	%		6.25 	%		6.00 	%	

NA    Not applicable.

		Pension Plans	
		Year Ended December 31,	
Assumption – Rate of Compensation Increase (a)		2020		2019		2018	
AEP		5.00 	%		4.95 	%		4.85 	%	
AEP Texas		5.05 	%		5.00 	%		4.95 	%	
APCo		4.85 	%		4.75 	%		4.75 	%	
I&M		5.00 	%		4.95 	%		4.90 	%	
OPCo		5.25 	%		5.20 	%		5.00 	%	
PSO		5.05 	%		5.05 	%		4.90 	%	
SWEPCo		4.90 	%		4.90 	%		4.85 	%	

(a)Rates are for base pay only.  In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third-party forecasts and current prospects for economic growth.  The expected return on plan assets is the same for each Registrant.

The health care trend rate assumptions used for OPEB plans measurement purposes are shown below:

		December 31,	
Health Care Trend Rates		2020		2019	
Initial		6.50 	%	 	6.00 	%	
Ultimate		4.50 	%	 	4.50 	%	
Year Ultimate Reached		2029	 	2026	

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Significant Concentrations of Risk within Plan Assets

In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets.  The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits.  The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment.  Management monitors the plans to control security diversification and ensure compliance with the investment policy.  As of December 31, 2020, the assets were invested in compliance with all investment limits.  See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.

Benefit Plan Obligations, Plan Assets, Funded Status and Amounts Recognized on the Balance Sheets

For the year ended December 31, 2020, the pension plans had an actuarial loss primarily due to a decrease in the discount rate, partially offset by a decrease in the assumed rate used to convert account balances to annuities. For the year ended December 31, 2020, the OPEB plans had an actuarial loss primarily due to a decrease in the discount rate and an update to the health care trend assumption, partially offset by updated projected per capita claims costs due to rate negotiations for Medicare advantage premium rates. For the year ended December 31, 2019, the pension plans had an actuarial loss due to a decrease in the discount rate, partially offset by updates to the mortality table. For the year ended December 31, 2019, the OPEB plans had an actuarial loss due to a decrease in the discount rate and an update to the persistency assumption, partially offset by an update to the projected per capita cost assumption as well as savings resulting from legislation signed in December 2019 which eliminated two Affordable Care Act taxes. The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets, funded status and the presentation on the balance sheets.  The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.

AEP		Pension Plans		OPEB	
		2020		2019		2020		2019	
Change in Benefit Obligation		(in millions)	
Benefit Obligation as of January 1,		$	5,236.8 			$	4,810.3 			$	1,225.4 			$	1,194.5 		
Service Cost		111.9 			95.5 			10.0 			9.5 		
Interest Cost		167.9 			204.4 			39.8 			50.5 		
Actuarial Loss		434.7 			493.6 			39.3 			58.8 		
Plan Amendments		— 			0.2 			(11.4)			(11.0)		
Benefit Payments		(406.8)			(367.2)			(131.0)			(113.0)		
Participant Contributions		— 			— 			38.2 			35.5 		
Medicare Subsidy		— 			— 			0.6 			0.6 		
Benefit Obligation as of December 31,		$	5,544.5 			$	5,236.8 			$	1,210.9 			$	1,225.4 		
									
Change in Fair Value of Plan Assets									
Fair Value of Plan Assets as of January 1,		$	5,015.4 			$	4,695.9 			$	1,781.8 			$	1,534.2 		
Actual Gain on Plan Assets		832.4 			681.1 			253.0 			321.0 		
Company Contributions (a)		115.6 			5.6 			4.7 			4.1 		
Participant Contributions		— 			— 			38.2 			35.5 		
Benefit Payments		(406.8)			(367.2)			(131.0)			(113.0)		
Fair Value of Plan Assets as of December 31,		$	5,556.6 			$	5,015.4 			$	1,946.7 			$	1,781.8 		
									
Funded (Underfunded) Status as of December 31,		$	12.1 			$	(221.4)			$	735.8 			$	556.4 		

(a)Contributions to the qualified pension plan were $110 million and $0 for the years ended December 31, 2020 and 2019, respectively. Contributions to the non-qualified pension plans were $6 million and $6 million for the years ended December 31, 2020 and 2019, respectively.
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		Pension Plans		OPEB	
		December 31,	
AEP		2020		2019		2020		2019	
		(in millions)	
Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs		$	93.5 			$	— 			$	771.9 			$	590.8 		
Other Current Liabilities – Accrued Short-term Benefit Liability		(6.7)			(6.1)			(2.4)			(2.6)		
Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability		(74.7)			(215.3)			(33.7)			(31.8)		
Funded (Underfunded) Status		$	12.1 			$	(221.4)			$	735.8 			$	556.4 		

																											
AEP Texas		Pension Plans		OPEB	
		2020		2019		2020		2019	
Change in Benefit Obligation		(in millions)	
Benefit Obligation as of January 1,		$	441.2 			$	409.3 			$	97.8 			$	95.9 		
Service Cost		10.0 			8.6 			0.8 			0.8 		
Interest Cost		13.9 			17.5 			3.2 			4.0 		
Actuarial Loss		28.1 			40.1 			2.4 			3.9 		
Plan Amendments		— 			— 			(1.0)			(0.9)		
Benefit Payments		(40.0)			(34.3)			(10.0)			(8.8)		
Participant Contributions		— 			— 			3.1 			2.9 		
	
Benefit Obligation as of December 31,		$	453.2 			$	441.2 			$	96.3 			$	97.8 		
									
Change in Fair Value of Plan Assets									
Fair Value of Plan Assets as of January 1,		$	435.1 			$	410.7 			$	148.1 			$	129.9 		
Actual Gain on Plan Assets		67.2 			58.3 			21.1 			24.0 		
Company Contributions		11.7 			0.4 			— 			0.1 		
Participant Contributions		— 			— 			3.1 			2.9 		
Benefit Payments		(40.0)			(34.3)			(10.0)			(8.8)		
Fair Value of Plan Assets as of December 31,		$	474.0 			$	435.1 			$	162.3 			$	148.1 		
									
Funded (Underfunded) Status as of December 31,		$	20.8 			$	(6.1)			$	66.0 			$	50.3 		

																											
		Pension Plans		OPEB	
		December 31,	
AEP Texas		2020		2019		2020		2019	
		(in millions)	
Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs		$	24.7 			$	— 			$	66.0 			$	50.3 		
Other Current Liabilities – Accrued Short-term Benefit Liability		(0.4)			(0.4)			— 			— 		
Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability		(3.5)			(5.7)			— 			— 		
Funded (Underfunded) Status		$	20.8 			$	(6.1)			$	66.0 			$	50.3 		

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APCo		Pension Plans		OPEB	
		2020		2019		2020		2019	
Change in Benefit Obligation		(in millions)	
Benefit Obligation as of January 1,		$	647.2 			$	603.1 			$	203.5 			$	205.5 		
Service Cost		10.5 			9.4 			1.0 			1.0 		
Interest Cost		20.3 			25.2 			6.6 			8.7 		
Actuarial Loss		40.0 			52.9 			5.6 			4.7 		
Plan Amendments		— 			— 			(1.8)			(1.7)		
Benefit Payments		(47.2)			(43.4)			(23.2)			(20.8)		
Participant Contributions		— 			— 			6.3 			5.9 		
Medicare Subsidy		— 			— 			0.2 			0.2 		
Benefit Obligation as of December 31,		$	670.8 			$	647.2 			$	198.2 			$	203.5 		
									
Change in Fair Value of Plan Assets									
Fair Value of Plan Assets as of January 1,		$	637.0 			$	593.3 			$	271.0 			$	238.4 		
Actual Gain on Plan Assets		104.5 			87.1 			36.8 			45.3 		
Company Contributions		7.0 			— 			2.1 			2.2 		
Participant Contributions		— 			— 			6.3 			5.9 		
Benefit Payments		(47.2)			(43.4)			(23.2)			(20.8)		
Fair Value of Plan Assets as of December 31,		$	701.3 			$	637.0 			$	293.0 			$	271.0 		
									
Funded (Underfunded) Status as of December 31,		$	30.5 			$	(10.2)			$	94.8 			$	67.5 		

																											
		Pension Plans		OPEB	
		December 31,	
APCo		2020		2019		2020		2019	
		(in millions)	
Employee Benefits and Pension Assets – Prepaid Benefit Costs		$	31.0 			$	— 			$	119.1 			$	92.0 		
Other Current Liabilities – Accrued Short-term Benefit Liability		— 			— 			(1.8)			(2.0)		
Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability		(0.5)			(10.2)			(22.5)			(22.5)		
Funded (Underfunded) Status		$	30.5 			$	(10.2)			$	94.8 			$	67.5 		
297

																											
I&M		Pension Plans		OPEB	
		2020		2019		2020		2019	
Change in Benefit Obligation		(in millions)	
Benefit Obligation as of January 1,		$	616.1 			$	567.0 			$	142.9 			$	138.3 		
Service Cost		15.4 			13.4 			1.4 			1.4 		
Interest Cost		19.7 			23.8 			4.7 			5.8 		
Actuarial Loss		44.3 			49.8 			5.1 			8.1 		
Plan Amendments		— 			— 			(1.6)			(1.5)		
Benefit Payments		(42.2)			(37.9)			(15.9)			(13.6)		
Participant Contributions		— 			— 			4.8 			4.4 		
	
Benefit Obligation as of December 31,		$	653.3 			$	616.1 			$	141.4 			$	142.9 		
									
Change in Fair Value of Plan Assets									
Fair Value of Plan Assets as of January 1,		$	630.5 			$	583.8 			$	216.3 			$	187.3 		
Actual Gain on Plan Assets		103.3 			84.6 			33.0 			38.2 		
Company Contributions		6.5 			— 			— 			— 		
Participant Contributions		— 			— 			4.8 			4.4 		
Benefit Payments		(42.2)			(37.9)			(15.9)			(13.6)		
Fair Value of Plan Assets as of December 31,		$	698.1 			$	630.5 			$	238.2 			$	216.3 		
									
Funded Status as of December 31,		$	44.8 			$	14.4 			$	96.8 			$	73.4 		

																											
		Pension Plans		OPEB	
		December 31,	
I&M		2020		2019		2020		2019	
		(in millions)	
Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs		$	46.5 			$	15.8 			$	96.8 			$	73.4 		
	
Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability		(1.7)			(1.4)			— 			— 		
Funded Status		$	44.8 			$	14.4 			$	96.8 			$	73.4 		

298

																											
OPCo		Pension Plans		OPEB	
		2020		2019		2020		2019	
Change in Benefit Obligation		(in millions)	
Benefit Obligation as of January 1,		$	487.8 			$	453.9 			$	130.2 			$	129.5 		
Service Cost		9.7 			7.9 			0.9 			0.8 		
Interest Cost		15.4 			19.1 			4.2 			5.5 		
Actuarial Loss		33.4 			40.5 			3.1 			4.9 		
Plan Amendments		— 			— 			(1.3)			(1.2)		
Benefit Payments		(36.0)			(33.6)			(15.0)			(13.5)		
Participant Contributions		— 			— 			4.3 			4.1 		
Medicare Subsidy		— 			— 			— 			0.1 		
Benefit Obligation as of December 31,		$	510.3 			$	487.8 			$	126.4 			$	130.2 		
									
Change in Fair Value of Plan Assets									
Fair Value of Plan Assets as of January 1,		$	499.1 			$	466.1 			$	197.1 			$	175.4 		
Actual Gain on Plan Assets		79.9 			66.6 			26.6 			31.1 		
Company Contributions		0.1 			— 			— 			— 		
Participant Contributions		— 			— 			4.3 			4.1 		
Benefit Payments		(36.0)			(33.6)			(15.0)			(13.5)		
Fair Value of Plan Assets as of December 31,		$	543.1 			$	499.1 			$	213.0 			$	197.1 		
									
Funded Status as of December 31,		$	32.8 			$	11.3 			$	86.6 			$	66.9 		

																											
		Pension Plans		OPEB	
		December 31,	
OPCo		2020		2019		2020		2019	
		(in millions)	
Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs		$	33.3 			$	11.7 			$	86.6 			$	66.9 		
	
Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability		(0.5)			(0.4)			— 			— 		
Funded Status		$	32.8 			$	11.3 			$	86.6 			$	66.9 		

299

																											
PSO		Pension Plans		OPEB	
		2020		2019		2020		2019	
Change in Benefit Obligation		(in millions)	
Benefit Obligation as of January 1,		$	267.5 			$	253.8 			$	64.7 			$	62.3 		
Service Cost		7.3 			6.5 			0.7 			0.6 		
Interest Cost		8.5 			10.6 			2.1 			2.6 		
Actuarial Loss		17.7 			16.8 			1.9 			3.8 		
Plan Amendments		— 			— 			(0.7)			(0.7)		
Benefit Payments		(21.1)			(20.2)			(6.8)			(5.9)		
Participant Contributions		— 			— 			2.1 			2.0 		
	
Benefit Obligation as of December 31,		$	279.9 			$	267.5 			$	64.0 			$	64.7 		
									
Change in Fair Value of Plan Assets									
Fair Value of Plan Assets as of January 1,		$	276.2 			$	261.2 			$	98.0 			$	84.3 		
Actual Gain on Plan Assets		44.6 			34.7 			14.5 			17.6 		
Company Contributions		0.1 			0.5 			— 			— 		
Participant Contributions		— 			— 			2.1 			2.0 		
Benefit Payments		(21.1)			(20.2)			(6.8)			(5.9)		
Fair Value of Plan Assets as of December 31,		$	299.8 			$	276.2 			$	107.8 			$	98.0 		
									
Funded Status as of December 31,		$	19.9 			$	8.7 			$	43.8 			$	33.3 		

																											
		Pension Plans		OPEB	
		December 31,	
PSO		2020		2019		2020		2019	
		(in millions)	
Employee Benefits and Pension Assets – Prepaid Benefit Costs		$	21.9 			$	10.6 			$	43.8 			$	33.3 		
Other Current Liabilities – Accrued Short-term Benefit Liability		(0.1)			(0.1)			— 			— 		
Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability		(1.9)			(1.8)			— 			— 		
Funded Status		$	19.9 			$	8.7 			$	43.8 			$	33.3 		
300

																											
SWEPCo		Pension Plans		OPEB	
		2020		2019		2020		2019	
Change in Benefit Obligation		(in millions)	
Benefit Obligation as of January 1,		$	314.2 			$	291.4 			$	77.4 			$	72.7 		
Service Cost		9.9 			8.6 			0.8 			0.8 		
Interest Cost		10.2 			12.4 			2.5 			3.1 		
Actuarial Loss		27.4 			25.5 			2.5 			6.0 		
Plan Amendments		— 			— 			(0.8)			(0.8)		
Benefit Payments		(27.2)			(23.7)			(7.7)			(6.6)		
Participant Contributions		— 			— 			2.4 			2.2 		
	
Benefit Obligation as of December 31,		$	334.5 			$	314.2 			$	77.1 			$	77.4 		
									
Change in Fair Value of Plan Assets									
Fair Value of Plan Assets as of January 1,		$	296.9 			$	281.0 			$	117.2 			$	98.5 		
Actual Gain on Plan Assets		48.2 			39.5 			18.0 			23.1 		
Company Contributions		9.0 			0.1 			— 			— 		
Participant Contributions		— 			— 			2.4 			2.2 		
Benefit Payments		(27.2)			(23.7)			(7.7)			(6.6)		
Fair Value of Plan Assets as of December 31,		$	326.9 			$	296.9 			$	129.9 			$	117.2 		
									
Funded (Underfunded) Status as of December 31,		$	(7.6)			$	(17.3)			$	52.8 			$	39.8 		

																											
		Pension Plans		OPEB	
		December 31,	
SWEPCo		2020		2019		2020		2019	
		(in millions)	
Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs		$	— 			$	— 			$	52.8 			$	39.8 		
Other Current Liabilities – Accrued Short-term Benefit Liability		(0.1)			(0.1)			— 			— 		
Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability		(7.5)			(17.2)			— 			— 		
Funded (Underfunded) Status		$	(7.6)			$	(17.3)			$	52.8 			$	39.8 		

301

Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI

The following tables show the components of the plans included in Regulatory Assets, Deferred Income Taxes and AOCI and the items attributable to the change in these components:

																											
AEP		Pension Plans		OPEB	
		December 31,	
		2020		2019		2020		2019	
Components		(in millions)	
Net Actuarial Loss		$	1,179.6 			$	1,406.2 			$	101.9 			$	225.8 		
Prior Service Cost (Credit)		0.2 			0.2 			(227.3)			(285.7)		
									
Recorded as									
Regulatory Assets		$	1,182.4 			$	1,351.8 			$	(99.0)			$	(46.8)		
Deferred Income Taxes		(0.5)			11.5 			(5.5)			(2.7)		
Net of Tax AOCI		(2.1)			43.1 			(20.9)			(10.4)		

																											
AEP		Pension Plans		OPEB	
		2020		2019		2020		2019	
Components		(in millions)	
Actuarial (Gain) Loss During the Year		$	(132.9)			$	108.6 			$	(118.0)			$	(171.9)		
Amortization of Actuarial Loss		(93.7)			(57.6)			(5.9)			(22.1)		
Prior Service (Credit) Cost		— 			0.2 			(11.4)			(7.6)		
Amortization of Prior Service Credit		— 			— 			69.8 			69.1 		
Change for the Year Ended December 31,		$	(226.6)			$	51.2 			$	(65.5)			$	(132.5)		

																											
AEP Texas		Pension Plans		OPEB	
		December 31,	
		2020		2019		2020		2019	
Components		(in millions)	
Net Actuarial Loss		$	160.5 			$	184.7 			$	12.3 			$	23.5 		
Prior Service Credit		— 			— 			(19.3)			(24.2)		
									
Recorded as									
Regulatory Assets		$	151.3 			$	172.2 			$	(6.3)			$	(0.2)		
Deferred Income Taxes		2.0 			2.7 			(0.1)			(0.1)		
Net of Tax AOCI		7.2 			9.8 			(0.6)			(0.4)		

																											
AEP Texas		Pension Plans		OPEB	
		2020		2019		2020		2019	
Components		(in millions)	
Actuarial (Gain) Loss During the Year		$	(16.4)			$	7.6 			$	(10.7)			$	(12.7)		
Amortization of Actuarial Loss		(7.8)			(4.9)			(0.5)			(1.8)		
Prior Service Credit		— 			— 			(1.0)			(0.6)		
Amortization of Prior Service Credit		— 			— 			5.9 			5.9 		
Change for the Year Ended December 31,		$	(24.2)			$	2.7 			$	(6.3)			$	(9.2)		
302

																											
APCo		Pension Plans		OPEB	
		December 31,	
		2020		2019		2020		2019	
Components		(in millions)	
Net Actuarial Loss		$	126.3 			$	168.3 			$	11.1 			$	28.8 		
Prior Service Credit		— 			— 			(33.2)			(41.6)		
									
Recorded as									
Regulatory Assets		$	124.7 			$	166.3 			$	(10.3)			$	(5.5)		
Deferred Income Taxes		0.3 			0.3 			(2.5)			(1.5)		
Net of Tax AOCI		1.3 			1.7 			(9.3)			(5.8)		

																											
APCo		Pension Plans		OPEB	
		2020		2019		2020		2019	
Components		(in millions)	
Actuarial (Gain) Loss During the Year		$	(30.8)			$	3.1 			$	(16.8)			$	(26.4)		
Amortization of Actuarial Loss		(11.2)			(7.0)			(0.9)			(3.7)		
Prior Service Credit		— 			— 			(1.8)			(1.3)		
Amortization of Prior Service Credit		— 			— 			10.2 			10.1 		
Change for the Year Ended December 31,		$	(42.0)			$	(3.9)			$	(9.3)			$	(21.3)		

																											
I&M		Pension Plans		OPEB	
		December 31,	
		2020		2019		2020		2019	
Components		(in millions)	
Net Actuarial Loss		$	39.5 			$	76.0 			$	15.6 			$	32.7 		
Prior Service Credit		— 			— 			(31.0)			(39.0)		
									
Recorded as									
Regulatory Assets		$	40.3 			$	73.7 			$	(14.6)			$	(6.2)		
Deferred Income Taxes		(0.1)			0.5 			(0.2)			— 		
Net of Tax AOCI		(0.7)			1.8 			(0.6)			(0.1)		

																											
I&M		Pension Plans		OPEB	
		2020		2019		2020		2019	
Components		(in millions)	
Actuarial (Gain) Loss During the Year		$	(25.7)			$	2.0 			$	(16.4)			$	(19.3)		
Amortization of Actuarial Loss		(10.8)			(6.6)			(0.7)			(2.7)		
Prior Service Credit		— 			— 			(1.5)			(1.0)		
Amortization of Prior Service Credit		— 			— 			9.5 			9.4 		
Change for the Year Ended December 31,		$	(36.5)			$	(4.6)			$	(9.1)			$	(13.6)		
303

																											
OPCo		Pension Plans		OPEB	
		December 31,	
		2020		2019		2020		2019	
Components		(in millions)	
Net Actuarial Loss		$	150.0 			$	178.7 			$	3.6 			$	17.2 		
Prior Service Credit		— 			— 			(22.9)			(28.6)		
									
Recorded as									
Regulatory Assets		$	150.0 			$	178.7 			$	(19.3)			$	(11.4)		

																											
OPCo		Pension Plans		OPEB	
		2020		2019		2020		2019	
Components		(in millions)	
Actuarial (Gain) Loss During the Year		$	(20.2)			$	3.3 			$	(12.9)			$	(15.8)		
Amortization of Actuarial Loss		(8.5)			(5.3)			(0.7)			(2.5)		
Prior Service Credit		— 			— 			(1.3)			(0.8)		
Amortization of Prior Service Credit		— 			— 			7.0 			6.9 		
Change for the Year Ended December 31,		$	(28.7)			$	(2.0)			$	(7.9)			$	(12.2)		

																											
PSO		Pension Plans		OPEB	
		December 31,	
		2020		2019		2020		2019	
Components		(in millions)	
Net Actuarial Loss		$	55.9 			$	73.0 			$	10.5 			$	18.2 		
Prior Service Credit		— 			— 			(14.1)			(17.8)		
									
Recorded as									
Regulatory Assets		$	55.9 			$	73.0 			$	(3.6)			$	0.4 		

																											
PSO		Pension Plans		OPEB	
		2020		2019		2020		2019	
Components		(in millions)	
Actuarial Gain During the Year		$	(12.4)			$	(1.7)			$	(7.4)			$	(8.9)		
Amortization of Actuarial Loss		(4.7)			(2.9)			(0.3)			(1.2)		
Prior Service Credit		— 			— 			(0.7)			(0.5)		
Amortization of Prior Service Credit		— 			— 			4.4 			4.3 		
Change for the Year Ended December 31,		$	(17.1)			$	(4.6)			$	(4.0)			$	(6.3)		
304

																											
SWEPCo		Pension Plans		OPEB	
		December 31,	
		2020		2019		2020		2019	
Components		(in millions)	
Net Actuarial Loss		$	86.9 			$	97.8 			$	11.5 			$	21.1 		
Prior Service Credit		— 			— 			(17.2)			(21.6)		
									
Recorded as									
Regulatory Assets		$	86.9 			$	97.8 			$	(3.0)			$	— 		
Deferred Income Taxes		— 			— 			(0.5)			— 		
Net of Tax AOCI		— 			— 			(2.2)			(0.5)		

																											
SWEPCo		Pension Plans		OPEB	
		2020		2019		2020		2019	
Components		(in millions)	
Actuarial (Gain) Loss During the Year		$	(5.2)			$	3.8 			$	(9.2)			$	(11.4)		
Amortization of Actuarial Loss		(5.7)			(3.4)			(0.4)			(1.4)		
Prior Service Credit		— 			— 			(0.8)			(0.6)		
Amortization of Prior Service Credit		— 			— 			5.2 			5.2 		
Change for the Year Ended December 31,		$	(10.9)			$	0.4 			$	(5.2)			$	(8.2)		

Determination of Pension Expense

The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return.

Pension and OPEB Assets

The fair value tables within Pension and OPEB Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries using the percentages in the table below:

		Pension Plan		OPEB	
		December 31,	
Company		2020		2019		2020		2019	
AEP Texas		8.5 	%		8.7 	%		8.3 	%		8.3 	%	
APCo		12.6 	%		12.7 	%		15.1 	%		15.2 	%	
I&M		12.6 	%		12.6 	%		12.2 	%		12.1 	%	
OPCo		9.8 	%		10.0 	%		10.9 	%		11.1 	%	
PSO		5.4 	%		5.5 	%		5.5 	%		5.5 	%	
SWEPCo		5.9 	%		5.9 	%		6.7 	%		6.6 	%	

305

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2020:

Asset Class		Level 1		Level 2		Level 3		Other		Total		Year End
Allocation	
		(in millions)			
Equities (a):													
Domestic		$	542.3 			$	— 			$	— 			$	— 			$	542.3 			9.7 	%	
International		676.3 			— 			— 			— 			676.3 			12.2 	%	

Common Collective Trusts (c)		— 			— 			— 			650.0 			650.0 			11.7 	%	
Subtotal – Equities		1,218.6 			— 			— 			650.0 			1,868.6 			33.6 	%	
													
Fixed Income (a):													
United States Government and Agency Securities		(1.4)			1,134.1 			— 			— 			1,132.7 			20.4 	%	
Corporate Debt		— 			1,425.0 			— 			— 			1,425.0 			25.6 	%	
Foreign Debt		— 			214.0 			— 			— 			214.0 			3.9 	%	
State and Local Government		— 			56.0 			— 			— 			56.0 			1.0 	%	
Other – Asset Backed		— 			0.8 			— 			— 			0.8 			— 	%	
Subtotal – Fixed Income		(1.4)			2,829.9 			— 			— 			2,828.5 			50.9 	%	
													
Infrastructure (c)		— 			— 			— 			91.1 			91.1 			1.6 	%	
Real Estate (c)		— 			— 			— 			231.6 			231.6 			4.2 	%	
Alternative Investments (c)		— 			— 			— 			431.8 			431.8 			7.8 	%	

Cash and Cash Equivalents (c)		— 			49.3 			— 			58.2 			107.5 			1.9 	%	
Other – Pending Transactions and Accrued Income (b)		— 			— 			— 			(2.5)			(2.5)			— 	%	
													
Total		$	1,217.2 			$	2,879.2 			$	— 			$	1,460.2 			$	5,556.6 			100.0 	%	

(a)Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.
(b)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
(c)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.
306

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2020:

Asset Class		Level 1		Level 2		Level 3		Other		Total		Year End
Allocation	
		(in millions)			
Equities:													
Domestic		$	399.9 			$	— 			$	— 			$	— 			$	399.9 			20.6 	%	
International		290.7 			— 			— 			— 			290.7 			14.9 	%	
	
Common Collective Trusts (b)		— 			— 			— 			264.7 			264.7 			13.6 	%	
Subtotal – Equities		690.6 			— 			— 			264.7 			955.3 			49.1 	%	
													
Fixed Income:													
Common Collective Trust – Debt (b)		— 			— 			— 			186.4 			186.4 			9.6 	%	
United States Government and Agency Securities		(0.2)			199.7 			— 			— 			199.5 			10.2 	%	
Corporate Debt		— 			248.7 			— 			— 			248.7 			12.8 	%	
Foreign Debt		— 			34.9 			— 			— 			34.9 			1.8 	%	
State and Local Government		73.9 			13.1 			— 			— 			87.0 			4.5 	%	
	
Subtotal – Fixed Income		73.7 			496.4 			— 			186.4 			756.5 			38.9 	%	
													
Trust Owned Life Insurance:													
International Equities		— 			64.8 			— 			— 			64.8 			3.3 	%	
United States Bonds		— 			135.9 			— 			— 			135.9 			7.0 	%	
Subtotal – Trust Owned Life Insurance		— 			200.7 			— 			— 			200.7 			10.3 	%	
													
Cash and Cash Equivalents (b)		26.3 			— 			— 			5.7 			32.0 			1.6 	%	
Other – Pending Transactions and Accrued Income (a)		— 			— 			— 			2.2 			2.2 			0.1 	%	
													
Total		$	790.6 			$	697.1 			$	— 			$	459.0 			$	1,946.7 			100.0 	%	

(a)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
(b)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

307

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2019:

Asset Class		Level 1		Level 2		Level 3		Other		Total		Year End
Allocation	
		(in millions)			
Equities (a):													
Domestic		$	387.8 			$	— 			$	— 			$	— 			$	387.8 			7.8 	%	
International		609.1 			— 			— 			— 			609.1 			12.1 	%	

Common Collective Trusts (c)		— 			— 			— 			547.3 			547.3 			10.9 	%	
Subtotal – Equities		996.9 			— 			— 			547.3 			1,544.2 			30.8 	%	
													
Fixed Income (a):													
	
United States Government and Agency Securities		(5.8)			1,248.6 			— 			— 			1,242.8 			24.8 	%	
Corporate Debt		— 			1,143.7 			— 			— 			1,143.7 			22.8 	%	
Foreign Debt		— 			211.6 			— 			— 			211.6 			4.2 	%	
State and Local Government		— 			55.1 			— 			— 			55.1 			1.1 	%	
Other – Asset Backed		— 			3.6 			— 			— 			3.6 			0.1 	%	
Subtotal – Fixed Income		(5.8)			2,662.6 			— 			— 			2,656.8 			53.0 	%	
													
Infrastructure (c)		— 			— 			— 			85.8 			85.8 			1.7 	%	
Real Estate (c)		— 			— 			— 			239.4 			239.4 			4.8 	%	
Alternative Investments (c)		— 			— 			— 			448.3 			448.3 			8.9 	%	

Cash and Cash Equivalents (c)		— 			24.4 			— 			37.2 			61.6 			1.2 	%	
Other – Pending Transactions and Accrued Income (b)		— 			— 			— 			(20.7)			(20.7)			(0.4)	%	
													
Total		$	991.1 			$	2,687.0 			$	— 			$	1,337.3 			$	5,015.4 			100.0 	%	

(a)Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.
(b)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
(c)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.
308

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2019:

Asset Class		Level 1		Level 2		Level 3		Other		Total		Year End
Allocation	
		(in millions)			
Equities:													
Domestic		$	312.2 			$	— 			$	— 			$	— 			$	312.2 			17.5 	%	
International		251.5 			— 			— 			— 			251.5 			14.1 	%	
	
Common Collective Trusts (b)		— 			— 			— 			260.8 			260.8 			14.7 	%	
Subtotal – Equities		563.7 			— 			— 			260.8 			824.5 			46.3 	%	
													
Fixed Income:													
Common Collective Trust – Debt (b)		— 			— 			— 			177.6 			177.6 			10.0 	%	
United States Government and Agency Securities		(0.1)			214.4 			— 			— 			214.3 			12.0 	%	
Corporate Debt		— 			206.7 			— 			— 			206.7 			11.6 	%	
Foreign Debt		— 			35.5 			— 			— 			35.5 			2.0 	%	
State and Local Government		58.8 			14.8 			— 			— 			73.6 			4.1 	%	
Other – Asset Backed		— 			0.2 			— 			— 			0.2 			— 	%	
Subtotal – Fixed Income		58.7 			471.6 			— 			177.6 			707.9 			39.7 	%	
													
Trust Owned Life Insurance:													
International Equities		— 			60.2 			— 			— 			60.2 			3.4 	%	
United States Bonds		— 			151.6 			— 			— 			151.6 			8.5 	%	
Subtotal – Trust Owned Life Insurance		— 			211.8 			— 			— 			211.8 			11.9 	%	
													
Cash and Cash Equivalents (b)		26.7 			— 			— 			6.7 			33.4 			1.9 	%	
Other – Pending Transactions and Accrued Income (a)		— 			— 			— 			4.2 			4.2 			0.2 	%	
													
Total		$	649.1 			$	683.4 			$	— 			$	449.3 			$	1,781.8 			100.0 	%	

(a)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
(b)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

Accumulated Benefit Obligation

The accumulated benefit obligation for the pension plans is as follows:

Accumulated Benefit Obligation		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Qualified Pension Plan		$	5,171.3 			$	424.5 			$	645.8 			$	615.8 			$	479.2 			$	258.3 			$	307.1 		
Nonqualified Pension Plans		72.9 			3.6 			0.2 			0.8 			0.2 			1.6 			1.4 		
Total as of December 31, 2020		$	5,244.2 			$	428.1 			$	646.0 			$	616.6 			$	479.4 			$	259.9 			$	308.5 		

																																													
Accumulated Benefit Obligation		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Qualified Pension Plan		$	4,929.0 			$	417.5 			$	627.3 			$	586.3 			$	464.2 			$	248.9 			$	291.9 		
Nonqualified Pension Plans		69.7 			3.6 			0.2 			0.6 			0.1 			1.6 			1.3 		
Total as of December 31, 2019		$	4,998.7 			$	421.1 			$	627.5 			$	586.9 			$	464.3 			$	250.5 			$	293.2 		

309

Obligations in Excess of Fair Values

The tables below show the underfunded pension plans that had obligations in excess of plan assets.

Projected Benefit Obligation

	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
	(in millions)	
Projected Benefit Obligation	$	81.4 			$	3.9 			$	0.5 			$	1.7 			$	0.6 			$	2.0 			$	334.5 		
Fair Value of Plan Assets	— 			— 			— 			— 			— 			— 			326.9 		
Underfunded Projected Benefit Obligation as of December 31, 2020	$	(81.4)			$	(3.9)			$	(0.5)			$	(1.7)			$	(0.6)			$	(2.0)			$	(7.6)		

																																										
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
	(in millions)	
Projected Benefit Obligation	$	5,236.8 			$	441.2 			$	647.2 			$	1.5 			$	0.4 			$	1.9 			$	314.2 		
Fair Value of Plan Assets	5,015.4 			435.1 			637.0 			— 			— 			— 			296.9 		
Underfunded Projected Benefit Obligation as of December 31, 2019	$	(221.4)			$	(6.1)			$	(10.2)			$	(1.5)			$	(0.4)			$	(1.9)			$	(17.3)		

Accumulated Benefit Obligation

	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
	(in millions)	
Accumulated Benefit Obligation	$	72.9 			$	3.6 			$	0.2 			$	0.8 			$	0.2 			$	1.6 			$	1.4 		
Fair Value of Plan Assets	— 			— 			— 			— 			— 			— 			— 		
Underfunded Accumulated Benefit Obligation as of December 31, 2020	$	(72.9)			$	(3.6)			$	(0.2)			$	(0.8)			$	(0.2)			$	(1.6)			$	(1.4)		

																																										
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
	(in millions)	
Accumulated Benefit Obligation	$	69.7 			$	3.6 			$	0.2 			$	0.6 			$	0.1 			$	1.6 			$	1.3 		
Fair Value of Plan Assets	— 			— 			— 			— 			— 			— 			— 		
Underfunded Accumulated Benefit Obligation as of December 31, 2019	$	(69.7)			$	(3.6)			$	(0.2)			$	(0.6)			$	(0.1)			$	(1.6)			$	(1.3)		

Estimated Future Benefit Payments and Contributions

The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded non-qualified benefits.  For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan.   For OPEB plans, expected payments include the payment of unfunded benefits.  The following table provides the estimated contributions and payments by Registrant for 2021:

Company		Pension Plans		OPEB	
		(in millions)	
AEP		$	132.8 			$	3.1 		
AEP Texas		5.1 			0.1 		
APCo		1.8 			1.8 		
I&M		1.3 			— 		
	
PSO		0.1 			— 		
SWEPCo		7.1 			— 		

310

The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets.  The payments include the participants’ contributions to the plan for their share of the cost.  Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results.  The estimated payments for the pension benefits and OPEB are as follows:

Pension Plans		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
2021		$	385.3 			$	36.3 			$	44.7 			$	40.2 			$	35.4 			$	21.8 			$	25.2 		
2022		382.8 			35.9 			45.1 			42.4 			36.0 			21.2 			25.4 		
2023		384.3 			36.1 			45.1 			41.5 			34.2 			22.3 			25.7 		
2024		384.0 			35.9 			45.7 			42.7 			34.0 			21.9 			25.7 		
2025		377.1 			35.2 			44.0 			42.7 			33.3 			21.1 			25.3 		
Years 2026 to 2030, in Total		1,763.1 			154.1 			209.7 			205.2 			155.0 			94.8 			115.7 		

																																													
OPEB Benefit Payments		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
2021		$	121.6 			$	9.5 			$	21.1 			$	15.1 			$	13.7 			$	6.4 			$	7.5 		
2022		122.5 			9.9 			20.8 			15.3 			13.9 			6.7 			7.8 		
2023		117.4 			9.7 			19.8 			14.7 			13.2 			6.6 			7.6 		
2024		121.9 			10.3 			20.5 			15.3 			13.7 			6.9 			8.2 		
2025		120.9 			10.4 			20.0 			15.1 			13.4 			6.9 			8.2 		
Years 2026 to 2030, in Total		573.9 			48.6 			93.3 			70.9 			61.7 			32.1 			39.1 		

																																													
OPEB Medicare
Subsidy Receipts		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
2021		$	0.2 			$	— 			$	0.1 			$	— 			$	— 			$	— 			$	— 		
2022		0.2 			— 			0.1 			— 			— 			— 			— 		
2023		0.3 			— 			0.1 			— 			— 			— 			— 		
2024		0.3 			— 			0.1 			— 			— 			— 			— 		
2025		0.3 			— 			0.1 			— 			— 			— 			— 		
Years 2026 to 2030, in Total		1.5 			— 			0.6 			— 			— 			— 			— 		

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	
	Years Ended December 31,	
	2020		2019		2018		2020		2019		2018	
	(in millions)	
Service Cost	$	111.9 			$	95.5 			$	97.6 			$	10.0 			$	9.5 			$	11.6 		
Interest Cost	167.9 			204.4 			187.8 			39.8 			50.5 			47.4 		
Expected Return on Plan Assets	(264.9)			(296.0)			(290.3)			(95.6)			(93.7)			(102.2)		
	
Amortization of Prior Service Credit	— 			— 			— 			(69.8)			(69.1)			(69.1)		
Amortization of Net Actuarial Loss	93.7 			57.6 			85.2 			5.9 			22.1 			10.5 		
Settlements	— 			— 			2.6 			— 			— 			— 		
Net Periodic Benefit Cost (Credit)	108.6 			61.5 			82.9 			(109.7)			(80.7)			(101.8)		
Capitalized Portion	(47.0)			(38.6)			(41.1)			(4.2)			(3.8)			(4.9)		
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	61.6 			$	22.9 			$	41.8 			$	(113.9)			$	(84.5)			$	(106.7)		
311

																																				
AEP Texas	Pension Plans		OPEB	
	Years Ended December 31,	
	2020		2019		2018		2020		2019		2018	
	(in millions)	
Service Cost	$	10.0 			$	8.6 			$	9.2 			$	0.8 			$	0.8 			$	0.9 		
Interest Cost	13.9 			17.5 			16.0 			3.2 			4.0 			3.8 		
Expected Return on Plan Assets	(22.7)			(25.8)			(25.6)			(8.0)			(7.8)			(8.6)		
	
Amortization of Prior Service Credit	— 			— 			— 			(5.9)			(5.9)			(5.9)		
Amortization of Net Actuarial Loss	7.8 			4.9 			7.2 			0.5 			1.8 			0.8 		
Net Periodic Benefit Cost (Credit)	9.0 			5.2 			6.8 			(9.4)			(7.1)			(9.0)		
Capitalized Portion	(5.5)			(4.5)			(4.8)			(0.4)			(0.4)			(0.5)		
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	3.5 			$	0.7 			$	2.0 			$	(9.8)			$	(7.5)			$	(9.5)		

																																				
APCo	Pension Plans		OPEB	
	Years Ended December 31,	
	2020		2019		2018		2020		2019		2018	
	(in millions)	
Service Cost	$	10.5 			$	9.4 			$	9.3 			$	1.0 			$	1.0 			$	1.1 		
Interest Cost	20.3 			25.2 			23.5 			6.6 			8.7 			8.2 		
Expected Return on Plan Assets	(33.6)			(37.4)			(36.6)			(14.4)			(14.6)			(16.0)		
	
Amortization of Prior Service Credit	— 			— 			— 			(10.2)			(10.1)			(10.0)		
Amortization of Net Actuarial Loss	11.2 			7.0 			10.6 			0.9 			3.7 			1.9 		
Net Periodic Benefit Cost (Credit)	8.4 			4.2 			6.8 			(16.1)			(11.3)			(14.8)		
Capitalized Portion	(4.5)			(4.0)			(3.8)			(0.4)			(0.4)			(0.5)		
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	3.9 			$	0.2 			$	3.0 			$	(16.5)			$	(11.7)			$	(15.3)		

																																				
I&M	Pension Plans		OPEB	
	Years Ended December 31,	
	2020		2019		2018		2020		2019		2018	
	(in millions)	
Service Cost	$	15.4 			$	13.4 			$	13.6 			$	1.4 			$	1.4 			$	1.6 		
Interest Cost	19.7 			23.8 			22.1 			4.7 			5.8 			5.4 		
Expected Return on Plan Assets	(33.3)			(36.8)			(35.7)			(11.7)			(11.4)			(12.3)		
	
Amortization of Prior Service Credit	— 			— 			— 			(9.5)			(9.4)			(9.5)		
Amortization of Net Actuarial Loss	10.8 			6.6 			9.8 			0.7 			2.7 			1.2 		
Net Periodic Benefit Cost (Credit)	12.6 			7.0 			9.8 			(14.4)			(10.9)			(13.6)		
Capitalized Portion	(4.3)			(3.4)			(5.6)			(0.4)			(0.4)			(0.7)		
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	8.3 			$	3.6 			$	4.2 			$	(14.8)			$	(11.3)			$	(14.3)		

312

																																				
OPCo	Pension Plans		OPEB	
	Years Ended December 31,	
	2020		2019		2018		2020		2019		2018	
	(in millions)	
Service Cost	$	9.7 			$	7.9 			$	7.7 			$	0.9 			$	0.8 			$	0.9 		
Interest Cost	15.4 			19.1 			17.7 			4.2 			5.5 			5.1 		
Expected Return on Plan Assets	(26.3)			(29.3)			(28.8)			(10.5)			(10.8)			(11.7)		

Amortization of Prior Service Credit	— 			— 			— 			(7.0)			(6.9)			(6.9)		
Amortization of Net Actuarial Loss	8.5 			5.3 			8.0 			0.7 			2.5 			1.1 		
Net Periodic Benefit Cost (Credit)	7.3 			3.0 			4.6 			(11.7)			(8.9)			(11.5)		
Capitalized Portion	(5.0)			(3.7)			(3.6)			(0.5)			(0.4)			(0.4)		
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	2.3 			$	(0.7)			$	1.0 			$	(12.2)			$	(9.3)			$	(11.9)		

																																				
PSO	Pension Plans		OPEB	
	Years Ended December 31,	
	2020		2019		2018		2020		2019		2018	
	(in millions)	
Service Cost	$	7.3 			$	6.5 			$	7.0 			$	0.7 			$	0.6 			$	0.7 		
Interest Cost	8.5 			10.6 			9.9 			2.1 			2.6 			2.5 		
Expected Return on Plan Assets	(14.5)			(16.3)			(16.1)			(5.2)			(5.1)			(5.6)		
Amortization of Prior Service Credit	— 			— 			— 			(4.4)			(4.3)			(4.3)		
Amortization of Net Actuarial Loss	4.7 			2.9 			4.4 			0.3 			1.2 			0.5 		
Net Periodic Benefit Cost (Credit)	6.0 			3.7 			5.2 			(6.5)			(5.0)			(6.2)		
Capitalized Portion	(2.8)			(2.4)			(2.6)			(0.3)			(0.2)			(0.3)		
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	3.2 			$	1.3 			$	2.6 			$	(6.8)			$	(5.2)			$	(6.5)		

																																				
SWEPCo	Pension Plans		OPEB	
	Years Ended December 31,	
	2020		2019		2018		2020		2019		2018	
	(in millions)	
Service Cost	$	9.9 			$	8.6 			$	9.3 			$	0.8 			$	0.8 			$	0.9 		
Interest Cost	10.2 			12.4 			11.3 			2.5 			3.1 			2.8 		
Expected Return on Plan Assets	(15.7)			(17.7)			(17.3)			(6.3)			(5.9)			(6.4)		
Amortization of Prior Service Credit	— 			— 			— 			(5.2)			(5.2)			(5.2)		
Amortization of Net Actuarial Loss	5.7 			3.4 			5.1 			0.4 			1.4 			0.6 		
Settlements	— 			— 			0.4 			— 			— 			— 		
Net Periodic Benefit Cost (Credit)	10.1 			6.7 			8.8 			(7.8)			(5.8)			(7.3)		
Capitalized Portion	(3.4)			(2.9)			(3.1)			(0.3)			(0.3)			(0.3)		
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	6.7 			$	3.8 			$	5.7 			$	(8.1)			$	(6.1)			$	(7.6)		

American Electric Power System Retirement Savings Plan

AEP sponsors the American Electric Power System Retirement Savings Plan, a defined contribution retirement savings plan for substantially all employees who are not covered by a retirement savings plan of the UMWA.  This qualified plan offers participants an opportunity to contribute a portion of their pay, includes features under Section 401(k) of the Internal Revenue Code and provides for company matching contributions.  The matching contributions to the plan are 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions.

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The following table provides the cost for matching contributions to the retirement savings plans by Registrant:

		Year Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
AEP		$	81.8 			$	76.4 			$	71.8 		
AEP Texas		6.4 			5.9 			5.7 		
APCo		7.7 			7.5 			7.5 		
I&M		11.3 			11.0 			10.5 		
OPCo		7.3 			6.6 			6.3 		
PSO		4.9 			4.6 			4.5 		
SWEPCo		6.7 			6.2 			5.9 		

UMWA Benefits

Health and Welfare Benefits (Applies to AEP and APCo)

AEP provides health and welfare benefits negotiated with the UMWA for certain unionized employees, retirees and their survivors who meet eligibility requirements. APCo also provides the same UMWA health and welfare benefits for certain unionized mining retirees and their survivors who meet eligibility requirements.  AEP and APCo administer the health and welfare benefits and pay them from their general assets.

Multiemployer Pension Benefits (Applies to AEP)

UMWA pension benefits are provided through the United Mine Workers of America 1974 Pension Plan (Employer Identification Number: 52-1050282, Plan Number 002), a multiemployer plan. The UMWA pension benefits are administered by a board of trustees appointed in equal numbers by the UMWA and the Bituminous Coal Operators’ Association (BCOA), an industry bargaining association. AEP makes contributions to the United Mine Workers of America 1974 Pension Plan based on provisions in its labor agreement and the plan documents. The UMWA pension plan is different from single-employer plans as an employer’s contributions may be used to provide benefits to employees of other participating employers.  A withdrawing employer may be subject to a withdrawal liability, which is calculated based upon that employer’s share of the plan’s unfunded benefit obligations.  If an employer fails to make required contributions or if its payments in connection with its withdrawal liability fall short of satisfying its share of the plan’s unfunded benefit obligations, the remaining employers may be allocated a greater share of the remaining unfunded plan obligations. Under the Pension Protection Act of 2006 (PPA), the UMWA pension plan was in Critical and Declining Status for the plan years ending June 30, 2020 and 2019, without utilization of extended amortization provisions.  As required under the PPA, the Plan adopted a Rehabilitation Plan in 2015. The Rehabilitation Plan has been updated annually, most recently in April 2020.

The amounts contributed by AEP affiliates in 2020, 2019 and 2018 were immaterial and represent less than 5% of the total contributions in the plan’s latest annual report based on the plan year ended June 30, 2019.  The contributions in 2020, 2019 and 2018 did not include surcharges.

Under the terms of the UMWA pension plan, contributions will be required to continue beyond the December 31, 2020 expiration of the current collective bargaining agreement between the Cook Coal Terminal (CCT) facility and the UMWA, whether or not the term of that agreement is extended or a subsequent agreement is entered, so long as both the UMWA pension plan remains in effect and an AEP affiliate continues to operate the facility covered by the current collective bargaining agreement. The contribution rate applicable would be determined in accordance with the terms of the UMWA pension plan by reference to the National Bituminous Coal Wage Agreement, subject to periodic revisions, between the UMWA and the BCOA. If the UMWA pension plan would terminate or an AEP affiliate would cease operation of the facility without arranging for a successor operator to assume its liability, the withdrawal liability obligation would be triggered.

314

Based upon the planned closure of CCT in 2022, AEP records a UMWA pension withdrawal liability on the balance sheet. The UMWA pension withdrawal liability is re-measured annually and is the estimated value of the company’s anticipated contributions toward its proportionate share of the plan’s unfunded vested liabilities. As of December 31, 2020 and 2019, the liability balance was $25 million and $20 million, respectively. AEP recovers the estimated value of its UMWA pension withdrawal liability through fuel clauses in certain regulated jurisdictions. AEP records a regulatory asset on the balance sheets when the UMWA pension withdrawal liability exceeds the cumulative billings collected and a regulatory liability on the balance sheets when the cumulative billings collected exceed the withdrawal liability. As of December 31, 2020 and 2019, AEP recorded a regulatory asset on the balance sheets for $6 million and $2 million, respectively. If any portion of the UMWA pension withdrawal liability is not recoverable, it could reduce future net income and cash flows and impact financial condition.
315

9.  BUSINESS SEGMENTS

The disclosures in this note apply to all Registrants unless indicated otherwise.

AEP’s Reportable 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 to serve 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.
•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.

Generation & Marketing

•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, income tax expense and other nonallocated costs.
316

The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2020, 2019 and 2018 and reportable segment balance sheet information as of December 31, 2020 and 2019.  

	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)		Reconciling Adjustments		Consolidated	
	(in millions)	
2020														
Revenues from:														
External Customers	$	8,753.2 			$	4,238.7 			$	297.4 			$	1,621.0 			$	8.2 			$	— 			$	14,918.5 		
Other Operating Segments	126.2 			107.2 			901.4 			104.6 			88.6 			(1,328.0)			— 		
Total Revenues	$	8,879.4 			$	4,345.9 			$	1,198.8 			$	1,725.6 			$	96.8 			$	(1,328.0)			$	14,918.5 		

Depreciation and Amortization	$	1,600.5 			$	751.1 			$	257.6 			$	72.8 			$	0.8 			$	— 			$	2,682.8 		

Interest Expense	565.0 			289.2 			133.2 			24.0 			196.4 			(42.1)			1,165.7 		
Income Tax Expense (Benefit)	(7.0)			29.7 			130.8 			(108.0)			(5.0)			— 			40.5 		
Equity Earnings of Unconsolidated Subsidiaries	2.9 			— 			82.4 			3.2 			2.6 			— 			91.1 		

Net Income (Loss)	$	1,064.5 			$	496.4 			$	508.5 			$	216.9 			$	(89.6)			$	— 			$	2,196.7 		
														
Gross Property Additions	$	2,291.2 			$	2,108.1 			$	1,649.3 			$	197.0 			$	16.0 			$	(15.3)			$	6,246.3 		
														
Total Property, Plant and Equipment	$	49,023.3 			$	21,145.0 			$	11,827.2 			$	1,910.2 			$	407.3 			$	— 			$	84,313.0 		
Accumulated Depreciation and Amortization	15,586.2 			3,879.3 			595.7 			166.1 			184.1 			— 			20,411.4 		
Total Property, Plant and Equipment – Net	$	33,437.1 			$	17,265.7 			$	11,231.5 			$	1,744.1 			$	223.2 			$	— 			$	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 		
														
Investments in Equity Method Investees	$	37.1 			$	2.1 			$	831.3 			$	467.0 			$	68.8 			$	— 			$	1,406.3 		
														
Long-term Debt Due Within One Year:														
	
Nonaffiliated	$	1,034.6 			$	588.8 			$	52.3 			$	— 			$	410.4 		(d)	$	— 			$	2,086.1 		
														
Long-term Debt:														
Affiliated	65.0 			— 			— 			— 			— 			(65.0)			— 		
Nonaffiliated	12,375.6 			6,661.9 			4,075.7 			— 			5,873.2 		(d)	— 			28,986.4 		
														
Total Long-term Debt	$	13,475.2 			$	7,250.7 			$	4,128.0 			$	— 			$	6,283.6 			$	(65.0)			$	31,072.5 		

317

																																										
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)		Reconciling Adjustments		Consolidated	
	(in millions)	
2019														
Revenues from:														
External Customers	$	9,245.7 			$	4,319.0 			$	260.2 			$	1,721.8 			$	14.7 			$	— 			$	15,561.4 		
Other Operating Segments	121.4 			163.5 			813.0 			135.8 			81.1 			(1,314.8)			— 		
Total Revenues	$	9,367.1 			$	4,482.5 			$	1,073.2 			$	1,857.6 			$	95.8 			$	(1,314.8)			$	15,561.4 		
														
Asset Impairments and Other Related Charges	$	92.9 			$	32.5 			$	— 			$	31.0 			$	— 			$	— 			$	156.4 		
Depreciation and Amortization	1,447.0 			789.5 			183.4 			69.5 			0.6 			24.5 		(e)	2,514.5 		

Interest Expense	568.3 			243.3 			103.3 			30.0 			193.7 			(66.1)		(e)	1,072.5 		
Income Tax Expense (Benefit)	(97.7)			(25.2)			136.2 			(53.8)			27.6 			— 			(12.9)		
Equity Earnings (Loss) of Unconsolidated Subsidiaries	3.0 			— 			72.8 			(3.8)			0.1 			— 			72.1 		

Net Income (Loss)	$	985.6 			$	451.0 			$	520.1 			$	104.1 			$	(141.0)			$	— 			$	1,919.8 		
														
Gross Property Additions	$	2,437.4 			$	2,074.3 			$	1,458.9 			$	1,005.1 			$	14.5 			$	(20.4)			$	6,969.8 		
														
Total Property, Plant and Equipment	$	47,323.7 			$	19,773.3 			$	10,334.0 			$	1,650.8 			$	418.4 			$	(354.5)		(e)	$	79,145.7 		
Accumulated Depreciation and Amortization	14,580.4 			3,911.2 			418.9 			99.0 			184.5 			(186.4)		(e)	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)		(e)	$	60,138.1 		
														
Total Assets	$	41,228.8 			$	18,757.5 			$	11,143.5 			$	3,123.8 			$	5,440.0 		(b)	$	(3,801.3)		(c)(e)	$	75,892.3 		
														
Investments in Equity Method Investees	$	41.7 			$	2.5 			$	787.5 			$	459.5 			$	65.4 			$	— 			$	1,356.6 		
														
Long-term Debt Due Within One Year:														
Affiliated	$	20.0 			$	— 			$	— 			$	— 			$	— 			$	(20.0)			— 		
Nonaffiliated	704.7 			392.2 			— 			— 			501.8 		(d)	— 			1,598.7 		
														
Long-term Debt:														
Affiliated	39.0 			— 			— 			— 			— 			(39.0)			— 		
Nonaffiliated	12,162.0 			6,248.1 			3,593.8 			— 			3,122.9 			— 			25,126.8 		
														
Total Long-term Debt	$	12,925.7 			$	6,640.3 			$	3,593.8 			$	— 			$	3,624.7 		(d)	$	(59.0)			$	26,725.5 		
318

																																										
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other(a)		Reconciling Adjustments		Consolidated	
	(in millions)	
2018														
Revenues from:														
External Customers	$	9,556.7 			$	4,552.3 			$	248.6 			$	1,818.1 			$	20.0 			$	— 			$	16,195.7 		
Other Operating Segments	88.8 			100.8 			555.5 			122.2 			75.1 			(942.4)			— 		
Total Revenues	$	9,645.5 			$	4,653.1 			$	804.1 			$	1,940.3 			$	95.1 			$	(942.4)			$	16,195.7 		
														
Asset Impairments and Other Related Charges	$	3.4 			$	— 			$	— 			$	47.7 			$	19.5 			$	— 			$	70.6 		
Depreciation and Amortization	1,316.2 			734.1 			137.8 			41.0 			0.4 			57.1 		(e)	2,286.6 		

Interest Expense	567.8 			248.1 			90.7 			14.9 			122.6 			(59.7)		(e)	984.4 		
Income Tax Expense	5.7 			42.4 			95.3 			(49.2)			21.1 			— 			115.3 		
Equity Earnings of Unconsolidated Subsidiaries	2.7 			— 			68.7 			0.5 			1.2 			— 			73.1 		
														
Net Income (Loss)	$	995.5 			$	527.4 			$	373.0 			$	134.7 			$	(99.3)			$	— 			$	1,931.3 		
														
Gross Property Additions	$	2,282.2 			$	2,162.4 			$	1,614.1 			$	289.7 			$	16.3 			$	(39.2)			$	6,325.5 		
														
Total Assets	$	38,874.3 			$	17,083.4 			$	9,543.7 			$	1,979.7 			$	4,036.5 		(b)	$	(2,714.8)		(c)(e)	$	68,802.8 		

(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.
(c)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.
(d)Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information.
(e)Includes eliminations due to an intercompany finance lease.

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.
319

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 seven 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 years ended December 31, 2020, 2019 and 2018 and reportable segment balance sheet information as of December 31, 2020 and 2019.

	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo
Consolidated	
2020	(in millions)	
Revenues from:								
External Customers	$	248.8 			$	— 			$	— 			$	248.8 		
Sales to AEP Affiliates	896.3 			— 			— 			896.3 		
Other Revenues	0.6 			— 			— 			0.6 		
Total Revenues	$	1,145.7 			$	— 			$	— 			$	1,145.7 		
								
Depreciation and Amortization	$	249.0 			$	— 			$	— 			$	249.0 		
Interest Income	0.9 			149.6 			(148.1)		(a)	2.4 		
Allowance for Equity Funds Used During Construction	74.0 			— 			— 			74.0 		
Interest Expense	127.8 			148.1 			(148.1)		(a)	127.8 		
Income Tax Expense	106.5 			0.2 			— 			106.7 		

Net Income	$	422.3 			$	1.1 		(b)	$	— 			$	423.4 		
								
Gross Property Additions	$	1,621.9 			$	— 			$	— 			$	1,621.9 		
								
Total Transmission Property	$	11,345.6 			$	— 			$	— 			$	11,345.6 		
Accumulated Depreciation and Amortization	572.8 			— 			— 			572.8 		
Total Transmission Property - Net	$	10,772.8 			$	— 			$	— 			$	10,772.8 		
								
Notes Receivable - Affiliated	$	— 			$	3,948.5 			$	(3,948.5)		(c)	$	— 		
								
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 		
320

																								
	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo
Consolidated	
2019	(in millions)	
Revenues from:								
External Customers	$	214.6 			$	— 			$	— 			$	214.6 		
Sales to AEP Affiliates	806.7 			— 			— 			806.7 		
Other Revenues	0.1 			— 			— 			0.1 		
Total Revenues	$	1,021.4 			$	— 			$	— 			$	1,021.4 		
								
Depreciation and Amortization	$	176.0 			$	— 			$	— 			$	176.0 		
Interest Income	1.3 			123.8 			(122.1)		(a)	3.0 		
Allowance for Equity Funds Used During Construction	84.3 			— 			— 			84.3 		
Interest Expense	97.4 			122.1 			(122.1)		(a)	97.4 		
Income Tax Expense	117.1 			0.3 			— 			117.4 		

Net Income	$	438.6 			$	1.1 		(b)	$	— 			$	439.7 		
								
Gross Property Additions	$	1,419.5 			$	— 			$	— 			$	1,419.5 		
								
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 		

																								
	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo
Consolidated	
2018	(in millions)	
Revenues from:								
External Customers	$	177.0 			$	— 			$	— 			$	177.0 		
Sales to AEP Affiliates	598.9 			— 			— 			598.9 		
Other	0.2 			— 			— 			0.2 		
Total Revenues	$	776.1 			$	— 			$	— 			$	776.1 		
								
Depreciation and Amortization	$	133.9 			$	— 			$	— 			$	133.9 		
Interest Income	1.3 			104.6 			(103.4)		(a)	2.5 		
Allowance for Equity Funds Used During Construction	70.6 			— 			— 			70.6 		
Interest Expense	83.2 			103.4 			(103.4)		(a)	83.2 		
Income Tax Expense	83.9 			0.2 			— 			84.1 		

Net Income	$	314.9 			$	1.0 		(b)	$	— 			$	315.9 		
								
Gross Property Additions	$	1,570.8 			$	— 			$	— 			$	1,570.8 		
								
Total Assets	$	8,406.8 			$	2,857.1 		(d)	$	(2,869.8)		(e)	$	8,394.1 		

(a)    Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
(b)    Includes elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(c)    Elimination of intercompany debt.
(d)    Includes elimination of AEPTCo Parent’s investments in the State Transcos.
(e)    Primarily relates to elimination of Notes Receivable from the State Transcos.

321

10.  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.

322

The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts:

																																																			
				December 31, 2020	
Primary Risk
Exposure		Unit of
Measure		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
				(in millions)	
Commodity:																	
Power		MWhs		331.3 			— 			46.9 			19.7 			3.0 			11.9 			4.0 		
	
Natural Gas		MMBtus		26.9 			— 			— 			— 			— 			— 			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 			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		
																	
Interest Rate on Long-term Debt		USD		$	1,150.0 			$	— 			$	200.0 			$	— 			$	— 			$	— 			$	— 		

																																																			
				December 31, 2019	
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.
323

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 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 $3 million and $5 million as of December 31, 2020 and 2019, respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $7 million and $39 million as of December 31, 2020 and 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 Registrant Subsidiaries as of December 31, 2020 and 2019.
324

The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets:

AEP

																																							
		December 31, 2020	
		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		$	239.1 			$	21.1 			$	5.0 			$	265.2 			$	(170.5)			$	94.7 		
Long-term Risk Management Assets		275.9 			18.0 			— 			293.9 			(51.7)			242.2 		
Total Assets		515.0 			39.1 			5.0 			559.1 			(222.2)			336.9 		
													
Current Risk Management Liabilities		193.0 			54.4 			3.4 			250.8 			(172.0)			78.8 		
Long-term Risk Management Liabilities		222.2 			60.1 			4.1 			286.4 			(53.6)			232.8 		
Total Liabilities		415.2 			114.5 			7.5 			537.2 			(225.6)			311.6 		
													
Total MTM Derivative Contract Net Assets (Liabilities)		$	99.8 			$	(75.4)			$	(2.5)			$	21.9 			$	3.4 			$	25.3 		

																																							
		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 		

325

AEP Texas

		December 31, 2020	
		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		$	0.4 			$	(0.4)			$	— 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		0.4 			(0.4)			— 		
							
Current Risk Management Liabilities		— 			— 			— 		
Long-term Risk Management Liabilities		— 			— 			— 		
Total Liabilities		— 			— 			— 		
							
Total MTM Derivative Net Assets (Liabilities)		$	0.4 			$	(0.4)			$	— 		

																					
		December 31, 2019	
		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		$	— 			$	— 			$	— 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		— 			— 			— 		
							
Current Risk Management Liabilities		— 			— 			— 		
Long-term Risk Management Liabilities		— 			— 			— 		
Total Liabilities		— 			— 			— 		
							
Total MTM Derivative Contract Net Assets		$	— 			$	— 			$	— 		

326

APCo

		December 31, 2020	
		Risk				Gross Amounts 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 			— 			0.7 			(0.6)			0.1 		
Total Assets		39.5 			2.4 			41.9 			(19.4)			22.5 		
											
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 			— 			0.6 			(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 		

																					
		December 31, 2019	
		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		$	124.4 			$	(85.0)			$	39.4 		
Deferred Charges and Other Noncurrent Assets - 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 		
Deferred Credits and Other Noncurrent Liabilities - 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 		
327

I&M

		December 31, 2020	
		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		$	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 		

																					
		December 31, 2019	
		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		$	66.9 			$	(57.1)			$	9.8 		
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets		0.5 			(0.4)			0.1 		
Total Assets		67.4 			(57.5)			9.9 		
							
Other Current Liabilities - Current Risk Management Liabilities		55.2 			(54.7)			0.5 		
Deferred Credits and Other Noncurrent Liabilities - 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

		December 31, 2020	
		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		$	0.3 			$	(0.3)			$	— 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		0.3 			(0.3)			— 		
							
Current Risk Management Liabilities		8.7 			— 			8.7 		
Long-term Risk Management Liabilities		101.6 			— 			101.6 		
Total Liabilities		110.3 			— 			110.3 		
							
Total MTM Derivative Contract Net Liabilities		$	(110.0)			$	(0.3)			$	(110.3)		

																					
		December 31, 2019	
		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		$	— 			$	— 			$	— 		
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)		
328

PSO

		December 31, 2020	
		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		$	10.5 			$	(0.2)			$	10.3 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		10.5 			(0.2)			10.3 		
							
Current Risk Management Liabilities		— 			— 			— 		
Long-term Risk Management Liabilities		— 			— 			— 		
Total Liabilities		— 			— 			— 		
							
Total MTM Derivative Net Assets (Liabilities)		$	10.5 			$	(0.2)			$	10.3 		

																					
		December 31, 2019	
		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		$	16.3 			$	(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

		December 31, 2020	
		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		$	3.4 			$	(0.2)			$	3.2 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		3.4 			(0.2)			3.2 		
							
Current Risk Management Liabilities		0.7 			— 			0.7 		
Long-term Risk Management Liabilities		1.0 			— 			1.0 		
Total Liabilities		1.7 			— 			1.7 		
							
Total MTM Derivative Net Assets (Liabilities)		$	1.7 			$	(0.2)			$	1.5 		

																					
		December 31, 2019	
		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		$	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.
329

The tables below present the Registrants’ amount of gain (loss) recognized on risk management contracts:

																																													
		Year Ended December 31, 2020	
Location of Gain (Loss)		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Vertically Integrated Utilities Revenues		$	0.8 			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		
	
Generation & Marketing Revenues		9.5 			— 			— 			— 			— 			— 			— 		
Electric Generation, Transmission and Distribution Revenues		— 			— 			0.4 			0.1 			— 			— 			0.1 		

Purchased Electricity for Resale		1.4 			— 			1.2 			0.1 			— 			— 			— 		
Other Operation		(2.0)			(0.6)			(0.2)			(0.2)			(0.3)			(0.2)			(0.3)		
Maintenance		(2.9)			(0.8)			(0.4)			(0.3)			(0.5)			(0.3)			(0.4)		
Regulatory Assets (a)		(4.8)			— 			— 			(0.1)			(6.6)			— 			1.4 		
Regulatory Liabilities (a)		114.9 			0.4 			20.3 			12.4 			12.4 			39.1 			20.2 		
Total Gain (Loss) on Risk Management Contracts		$	116.9 			$	(1.0)			$	21.3 			$	12.0 			$	5.0 			$	38.6 			$	21.0 		

																																													
		Year Ended December 31, 2019	
Location of Gain (Loss)		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Vertically Integrated Utilities Revenues		$	0.7 			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		
	
Generation & Marketing Revenues		25.1 			— 			— 			— 			— 			— 			— 		
Electric Generation, Transmission and Distribution Revenues		— 			— 			0.1 			0.5 			— 			— 			0.1 		

Purchased Electricity for Resale		1.9 			— 			1.6 			0.1 			— 			— 			— 		
Other Operation		(0.8)			(0.2)			(0.1)			(0.1)			(0.2)			(0.1)			(0.1)		
Maintenance		(0.8)			(0.2)			(0.2)			(0.1)			(0.2)			(0.1)			(0.1)		
Regulatory Assets (a)		(3.7)			0.7 			0.3 			0.3 			(3.7)			1.2 			(1.5)		
Regulatory Liabilities (a)		102.6 			— 			2.4 			24.5 			10.1 			34.6 			26.6 		
Total Gain on Risk Management Contracts		$	125.0 			$	0.3 			$	4.1 			$	25.2 			$	6.0 			$	35.6 			$	25.0 		

																																													
		Year Ended December 31, 2018	
Location of Gain (Loss)		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Vertically Integrated Utilities Revenues		$	(10.4)			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		
	
Generation & Marketing Revenues		38.9 			— 			— 			— 			— 			— 			— 		
Electric Generation, Transmission and Distribution Revenues		— 			— 			(1.9)			(8.2)			— 			— 			0.1 		
	
Purchased Electricity for Resale		8.6 			— 			7.6 			0.8 			— 			— 			— 		
Other Operation		1.7 			0.4 			0.2 			0.2 			0.3 			0.2 			0.2 		
Maintenance		1.9 			0.4 			0.4 			0.2 			0.4 			0.2 			0.2 		
Regulatory Assets (a)		27.9 			(0.7)			(0.7)			7.1 			24.9 			(1.1)			(1.2)		
Regulatory Liabilities (a)		222.7 			(0.5)			135.5 			11.6 			— 			37.3 			11.9 		
Total Gain (Loss) on Risk Management Contracts		$	291.3 			$	(0.4)			$	141.1 			$	11.7 			$	25.6 			$	36.6 			$	11.2 		

(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
330

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.”

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
Assets/(Liabilities)		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities)	
		December 31, 2020		December 31, 2019		December 31, 2020		December 31, 2019	
		(in millions)	
Long-term Debt (a) (b)		$	(995.9)			$	(510.8)			$	(51.7)			$	(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 $(53) million and $0 as of December 31, 2020 and 2019, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.

The pretax effects of fair value hedge accounting on income were as follows:

	Years Ended December 31,	
	2020		2019		2018	
	(in millions)	
Gain (Loss) on Interest Rate Contracts:						
Fair Value Hedging Instruments (a)	$	41.1 			$	31.9 			$	(11.3)		
Fair Value Portion of Long-term Debt (a)	(41.1)			(31.9)			11.3 		

(a)Gain (Loss) is included in Interest Expense on the statements of income.

331

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 statement 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 years ended 2020, 2019 and 2018, AEP applied cash flow hedging to outstanding power derivatives. During the years ended 2020, 2019 and 2018, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives.

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 years ended 2020, 2019 and 2018, AEP applied cash flow hedging to outstanding interest rate derivatives. During the year ended 2020, APCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the year ended 2019, the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During the year ended 2018, SWEPCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not.

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

		December 31, 2020		December 31, 2019	
		Commodity		Interest Rate		Commodity		Interest Rate	
		(in millions)	
AOCI Gain (Loss) Net of Tax		$	(60.6)			$	(47.5)			$	(103.5)			$	(11.5)		
Portion Expected to be Reclassed to Net Income During the Next Twelve Months		(27.1)			(5.7)			(51.7)			(2.1)		

As of December 31, 2020 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 123 months and 120 months for commodity and interest rate hedges, respectively.
332

Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets

		December 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		$	(2.3)			$	(1.1)			$	(3.4)			$	(1.1)		
APCo		(0.8)			0.4 			0.9 			0.9 		
I&M		(8.3)			(1.6)			(9.9)			(1.6)		
	
PSO		0.1 			0.1 			1.1 			1.0 		
SWEPCo		(0.3)			(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.

Credit Risk

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, surety bonds 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. The Registrants had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2020 and 2019.

333

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, 2020	
		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		$	188.4 			$	— 			$	169.2 		
APCo		4.3 			— 			3.5 		
I&M		0.5 			— 			0.1 		
SWEPCo		1.8 			— 			1.8 		

																					
		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)

As of December 31, 2020, AEP held an $8 million investment in a privately held investee that is anticipated to complete an initial public offering (IPO) in the first quarter of 2021. The IPO is expected to be completed via a reverse merger with a public special purpose acquisition company. AEP’s interests in the investee as of December 31, 2020 consisted of a noncontrolling equity interest of preferred shares, which were accounted for at historical cost until completion of the IPO, and common share warrants, which management has determined are derivative instruments based on the accounting guidance for “Derivatives and Hedging”.

As of December 31, 2020, the warrants were valued at $32 million and were recorded in Deferred Charges and Other Noncurrent Assets on AEP’s balance sheet. AEP recognized an unrealized gain of $32 million associated with the warrants for the year ended December 31, 2020, presented in Other Income on AEP’s statement of income.

Management utilized a Black-Scholes options pricing model to value the warrants as of December 31, 2020. As the reverse merger and IPO did not close prior to the end of 2020, the valuation contemplated a liquidity adjustment that resulted in the overall fair value of the warrants being categorized as Level 3 in the fair value hierarchy. See “Fair Value Measurements of Financial Assets and Liabilities” section of Note 11 for additional information.
334

11.  FAIR VALUE MEASUREMENTS

The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.

Fair Value Measurements of Long-term Debt (Applies to all Registrants)

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value of AEP’s Equity Units (Level 1) are valued based on publicly-traded securities issued by AEP.

The book values and fair values of Long-term Debt are summarized in the following table:

		December 31,	
		2020		2019	
Company		Book Value		Fair Value		Book Value		Fair Value	
		(in millions)	
AEP (a)		$	31,072.5 			$	37,457.0 			$	26,725.5 			$	30,172.0 		
AEP Texas		4,820.4 			5,682.6 			4,558.4 			4,981.5 		
AEPTCo		3,948.5 			4,984.3 			3,427.3 			3,868.0 		
APCo		4,834.1 			6,391.8 			4,363.8 			5,253.1 		
I&M		3,029.9 			3,775.3 			3,050.2 			3,453.8 		
OPCo		2,430.2 			3,154.9 			2,082.0 			2,554.3 		
PSO		1,373.8 			1,732.1 			1,386.2 			1,603.3 		
SWEPCo		2,636.4 			3,210.1 			2,655.6 			2,927.9 		
(a)The fair value amounts include debt related to AEP’s Equity Units and had a fair value of $1.7 billion and $871 million as of December 31, 2020 and 2019, respectively. See “Equity Units” section of Note 14 for additional information.

Fair Value Measurements of Other Temporary Investments (Applies to AEP)

Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS.  See “Other Temporary Investments” section of Note 1 for additional information.

The following is a summary of Other Temporary Investments:

		December 31, 2020	
				Gross		Gross			
				Unrealized		Unrealized		Fair	
Other Temporary Investments		Cost		Gains		Losses		Value	
		(in millions)	
Restricted Cash and Other Cash Deposits (a)		$	68.3 			$	— 			$	— 			$	68.3 		
Fixed Income Securities – Mutual Funds (b)		120.7 			2.8 			— 			123.5 		
Equity Securities – Mutual Funds		25.9 			28.7 			— 			54.6 		
Total Other Temporary Investments		$	214.9 			$	31.5 			$	— 			$	246.4 		
335

																											
		December 31, 2019	
				Gross		Gross			
				Unrealized		Unrealized		Fair	
Other Temporary Investments		Cost		Gains		Losses		Value	
		(in millions)	
Restricted Cash and Other Cash Deposits (a)		$	214.7 			$	— 			$	— 			$	214.7 		
Fixed Income Securities – Mutual Funds (b)		123.2 			0.1 			— 			123.3 		
Equity Securities – Mutual Funds		29.2 			21.3 			— 			50.5 		
Total Other Temporary Investments		$	367.1 			$	21.4 			$	— 			$	388.5 		

(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.

The following table provides the activity for fixed income and equity securities within Other Temporary Investments:

		Years Ended December 31,	
		2020		2019		2018	
		(in millions)	
Proceeds from Investment Sales		$	50.9 			$	21.2 			$	— 		
Purchases of Investments		41.6 			45.0 			3.1 		
Gross Realized Gains on Investment Sales		3.8 			— 			— 		
Gross Realized Losses on Investment Sales		0.2 			0.4 			— 		

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)

Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value.  See “Nuclear Trust Funds” section of Note 1 for additional information.

The following is a summary of nuclear trust fund investments:

	December 31,	
	2020		2019	
			Gross		Other-Than-				Gross		Other-Than-	
	Fair		Unrealized		Temporary		Fair		Unrealized		Temporary	
	Value		Gains		Impairments		Value		Gains		Impairments	
	(in millions)	
Cash and Cash Equivalents	$	25.8 			$	— 			$	— 			$	15.3 			$	— 			$	— 		
Fixed Income Securities:												
United States Government	1,025.6 			98.5 			(7.1)			1,112.5 			55.5 			(6.1)		
Corporate Debt	86.3 			9.6 			(1.7)			72.4 			5.3 			(1.6)		
State and Local Government	114.3 			0.9 			(0.4)			7.6 			0.7 			(0.2)		
Subtotal Fixed Income Securities	1,226.2 			109.0 			(9.2)			1,192.5 			61.5 			(7.9)		
Equity Securities - Domestic (a)	2,054.7 			1,400.8 			— 			1,767.9 			1,144.4 			— 		
Spent Nuclear Fuel and Decommissioning Trusts	$	3,306.7 			$	1,509.8 			$	(9.2)			$	2,975.7 			$	1,205.9 			$	(7.9)		

(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.4 billion and $1.1 billion and unrealized losses of $9 million and $5 million as of December 31, 2020 and 2019, respectively.

336

The following table provides the securities activity within the decommissioning and SNF trusts:

	Years Ended December 31,	
	2020		2019		2018	
	(in millions)	
Proceeds from Investment Sales	$	1,593.4 			$	1,473.0 			$	2,010.0 		
Purchases of Investments	1,637.2 			1,531.0 			2,064.7 		
Gross Realized Gains on Investment Sales	26.4 			76.5 			47.5 		
Gross Realized Losses on Investment Sales	26.1 			24.3 			32.8 		

The base cost of fixed income securities was $1.1 billion and $1.1 billion as of December 31, 2020 and 2019, respectively.  The base cost of equity securities was $654 million and $623 million as of December 31, 2020 and 2019, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2020 was as follows:

	Fair Value of Fixed	
	Income Securities	
	(in millions)	
Within 1 year	$	294.8 		
After 1 year through 5 years	371.3 		
After 5 years through 10 years	214.4 		
After 10 years	345.7 		
Total	$	1,226.2 		

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Fair Value Measurements of Financial Assets and Liabilities

For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.

The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

AEP

		December 31, 2020	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	

	
Other Temporary Investments											
Restricted Cash and Other Cash Deposits (a)		$	57.8 			$	— 			$	— 			$	10.5 			$	68.3 		
Fixed Income Securities – Mutual Funds		123.5 			— 			— 			— 			123.5 		
Equity Securities – Mutual Funds (b)		54.6 			— 			— 			— 			54.6 		
Total Other Temporary Investments		235.9 			— 			— 			10.5 			246.4 		
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (d)		0.9 			258.8 			252.4 			(190.0)			322.1 		
Cash Flow Hedges:											
Commodity Hedges (c)		— 			34.4 			3.9 			(28.5)			9.8 		
Interest Rate Hedges		— 			2.4 			— 			— 			2.4 		
Fair Value Hedges		— 			2.6 			— 			— 			2.6 		
Total Risk Management Assets		0.9 			298.2 			256.3 			(218.5)			336.9 		
											
Spent Nuclear Fuel and Decommissioning Trusts											
Cash and Cash Equivalents (e)		16.8 			— 			— 			9.0 			25.8 		
Fixed Income Securities:											
United States Government		— 			1,025.6 			— 			— 			1,025.6 		
Corporate Debt		— 			86.3 			— 			— 			86.3 		
State and Local Government		— 			114.3 			— 			— 			114.3 		
Subtotal Fixed Income Securities		— 			1,226.2 			— 			— 			1,226.2 		
Equity Securities – Domestic (b)		2,054.7 			— 			— 			— 			2,054.7 		
Total Spent Nuclear Fuel and Decommissioning Trusts		2,071.5 			1,226.2 			— 			9.0 			3,306.7 		
											
Other Investments (h)		— 			— 			31.8 			— 			31.8 		
											
Total Assets		$	2,308.3 			$	1,524.4 			$	288.1 			$	(199.0)			$	3,921.8 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (d)		$	0.9 			$	244.2 			$	167.2 			$	(193.4)			$	218.9 		
Cash Flow Hedges:											
Commodity Hedges (c)		— 			106.1 			7.6 			(28.5)			85.2 		
Interest Rate Hedges		— 			3.4 			— 			— 			3.4 		
Fair Value Hedges		— 			4.1 			— 			— 			4.1 		
Total Risk Management Liabilities		$	0.9 			$	357.8 			$	174.8 			$	(221.9)			$	311.6 		
338

AEP

		December 31, 2019	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	

	
Other Temporary Investments											
Restricted Cash and Other Cash Deposits (a)		$	197.6 			$	— 			$	— 			$	17.1 			$	214.7 		
Fixed Income Securities – Mutual Funds		123.3 			— 			— 			— 			123.3 		
Equity Securities – Mutual Funds (b)		50.5 			— 			— 			— 			50.5 		
Total Other Temporary Investments		371.4 			— 			— 			17.1 			388.5 		
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (f)		4.0 			440.1 			369.2 			(404.5)			408.8 		
Cash Flow Hedges:											
Commodity Hedges (c)		— 			15.0 			3.2 			(6.7)			11.5 		
Interest Rate Hedges		— 			4.6 			— 			— 			4.6 		
Fair Value Hedges		— 			14.5 			— 			— 			14.5 		
Total Risk Management Assets		4.0 			474.2 			372.4 			(411.2)			439.4 		
											
Spent Nuclear Fuel and Decommissioning Trusts											
Cash and Cash Equivalents (e)		6.7 			— 			— 			8.6 			15.3 		
Fixed Income Securities:											
United States Government		— 			1,112.5 			— 			— 			1,112.5 		
Corporate Debt		— 			72.4 			— 			— 			72.4 		
State and Local Government		— 			7.6 			— 			— 			7.6 		
Subtotal Fixed Income Securities		— 			1,192.5 			— 			— 			1,192.5 		
Equity Securities – Domestic (b)		1,767.9 			— 			— 			— 			1,767.9 		
Total Spent Nuclear Fuel and Decommissioning Trusts		1,774.6 			1,192.5 			— 			8.6 			2,975.7 		
											
Total Assets		$	2,150.0 			$	1,666.7 			$	372.4 			$	(385.5)			$	3,803.6 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (f)		$	3.8 			$	450.0 			$	224.0 			$	(438.8)			$	239.0 		
Cash Flow Hedges:											
Commodity Hedges (c)		— 			105.3 			38.5 			(6.7)			137.1 		

Total Risk Management Liabilities		$	3.8 			$	555.3 			$	262.5 			$	(445.5)			$	376.1 		

339

AEP Texas

		December 31, 2020	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Restricted Cash for Securitized Funding		$	28.7 			$	— 			$	— 			$	— 			$	28.7 		
											
Risk Management Assets											
Risk Management Commodity Contracts (c)		— 			0.4 			— 			(0.4)			— 		
											
Total Assets		$	28.7 			$	0.4 			$	— 			$	(0.4)			$	28.7 		

	

																																	
		December 31, 2019	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Restricted Cash for Securitized Funding		$	154.7 			$	— 			$	— 			$	— 			$	154.7 		

	

	

	

APCo

		December 31, 2020	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Restricted Cash for Securitized Funding		$	16.9 			$	— 			$	— 			$	— 			$	16.9 		
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		— 			19.4 			19.9 			(19.2)			20.1 		
Cash Flow Hedges:											
Interest Rate Hedges		— 			2.4 			— 			— 			2.4 		
Total Risk Management Assets		— 			21.8 			19.9 			(19.2)			22.5 		
											
Total Assets		$	16.9 			$	21.8 			$	19.9 			$	(19.2)			$	39.4 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	19.5 			$	0.6 			$	(18.8)			$	1.3 		
Cash Flow Hedges:											
Interest Rate Hedges		— 			3.4 			— 			— 			3.4 		
Total Risk Management Liabilities		$	— 			$	22.9 			$	0.6 			$	(18.8)			$	4.7 		

																																	
		December 31, 2019	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Restricted Cash for Securitized Funding		$	23.5 			$	— 			$	— 			$	— 			$	23.5 		
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		— 			84.6 			40.5 			(85.6)			39.5 		
											
Total Assets		$	23.5 			$	84.6 			$	40.5 			$	(85.6)			$	63.0 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	84.0 			$	2.8 			$	(84.9)			$	1.9 		
340

I&M

																																	
		December 31, 2020	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	15.1 			$	2.5 			$	(13.9)			$	3.7 		
											
Spent Nuclear Fuel and Decommissioning Trusts											
Cash and Cash Equivalents (e)		16.8 			— 			— 			9.0 			25.8 		
Fixed Income Securities:											
United States Government		— 			1,025.6 			— 			— 			1,025.6 		
Corporate Debt		— 			86.3 			— 			— 			86.3 		
State and Local Government		— 			114.3 			— 			— 			114.3 		
Subtotal Fixed Income Securities		— 			1,226.2 			— 			— 			1,226.2 		
Equity Securities - Domestic (b)		2,054.7 			— 			— 			— 			2,054.7 		
Total Spent Nuclear Fuel and Decommissioning Trusts		2,071.5 			1,226.2 			— 			9.0 			3,306.7 		
											
Total Assets		$	2,071.5 			$	1,241.3 			$	2.5 			$	(4.9)			$	3,310.4 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	12.0 			$	0.4 			$	(12.2)			$	0.2 		

																																	
		December 31, 2019	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	59.5 			$	8.0 			$	(57.6)			$	9.9 		
											
Spent Nuclear Fuel and Decommissioning Trusts											
Cash and Cash Equivalents (e)		6.7 			— 			— 			8.6 			15.3 		
Fixed Income Securities:											
United States Government		— 			1,112.5 			— 			— 			1,112.5 		
Corporate Debt		— 			72.4 			— 			— 			72.4 		
State and Local Government		— 			7.6 			— 			— 			7.6 		
Subtotal Fixed Income Securities		— 			1,192.5 			— 			— 			1,192.5 		
Equity Securities - Domestic (b)		1,767.9 			— 			— 			— 			1,767.9 		
Total Spent Nuclear Fuel and Decommissioning Trusts		1,774.6 			1,192.5 			— 			8.6 			2,975.7 		
											
Total Assets		$	1,774.6 			$	1,252.0 			$	8.0 			$	(49.0)			$	2,985.6 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	53.4 			$	2.2 			$	(55.1)			$	0.5 		

341

OPCo

																																	
		December 31, 2020	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	

											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	0.3 			$	— 			$	(0.3)			$	— 		

	
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	110.3 			$	— 			$	110.3 		

																																	
		December 31, 2019	
		Level 1		Level 2		Level 3		Other		Total	
Liabilities:		(in millions)	

	

	

	
	
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	103.6 			$	— 			$	103.6 		

PSO

																																	
		December 31, 2020	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	0.2 			$	10.3 			$	(0.2)			$	10.3 		

	

																																	
		December 31, 2019	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	16.3 			$	(0.5)			$	15.8 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	0.5 			$	(0.5)			$	— 		
342

SWEPCo

																																	
		December 31, 2020	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	

	
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	0.1 			$	3.3 			$	(0.2)			$	3.2 		

	
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	1.7 			$	— 			$	1.7 		

																																	
		December 31, 2019	
		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	

	
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	6.5 			$	(0.1)			$	6.4 		

	
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	5.1 			$	(0.1)			$	5.0 		

(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.
(c)Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
(d)The December 31, 2020 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 2 matures $3 million in periods 2022-2024, $11 million in periods 2025-2026 and $1 million in periods 2027-2033; Level 3 matures $47 million in 2021, $37 million in periods 2022-2024, $14 million in periods 2025-2026 and $(13) million in periods 2027-2033. Risk management commodity contracts are substantially comprised of power contracts.
(e)Amounts in “Other” column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(f)The December 31, 2019 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 2 matures $(7) million in 2020 and $(3) million in periods 2021-2023; Level 3 matures $96 million in 2020, $36 million in periods 2021-2023, $25 million in periods 2024-2025 and $(12) million in periods 2026-2032.  Risk management commodity contracts are substantially comprised of power contracts.
(g)Substantially comprised of power contracts for the Registrant Subsidiaries.
(h)See “Warrants Held in Investee” section of Note 10 for additional information.

343

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

Year Ended December 31, 2020		AEP		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Balance as of December 31, 2019		$	109.9 			$	37.7 			$	5.8 			$	(103.6)			$	15.8 			$	1.4 		
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		39.5 			13.2 			2.5 			(1.6)			11.9 			2.8 		
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)		35.3 			— 			— 			— 			— 			— 		
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)		13.8 			— 			— 			— 			— 			— 		
Settlements		(113.1)			(51.6)			(8.6)			8.9 			(27.6)			(6.6)		
Transfers into Level 3 (d) (e)		(3.8)			— 			— 			— 			— 			— 		
Transfers out of Level 3 (e)		5.6 			0.7 			0.4 			— 			— 			— 		
Changes in Fair Value Allocated to Regulated Jurisdictions (f)		26.1 			19.3 			2.0 			(14.0)			10.2 			4.0 		
Balance as of December 31, 2020		$	113.3 			$	19.3 			$	2.1 			$	(110.3)			$	10.3 			$	1.6 		

																																							
Year Ended December 31, 2019		AEP		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Balance as of December 31, 2018		$	131.2 			$	57.8 			$	8.9 			$	(99.4)			$	9.5 			$	2.3 		
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		15.8 			(13.9)			4.7 			(0.9)			13.5 			6.0 		
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)		(0.1)			— 			— 			— 			— 			— 		
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)		(15.1)			— 			— 			— 			— 			— 		
Settlements		(117.6)			(42.5)			(13.0)			6.6 			(23.0)			(9.6)		
Transfers into Level 3 (d) (e)		(0.6)			(0.5)			(0.3)			— 			— 			— 		
Transfers out of Level 3 (e)		35.6 			(0.7)			(0.4)			— 			— 			— 		
Changes in Fair Value Allocated to Regulated Jurisdictions (f)		60.7 			37.5 			5.9 			(9.9)			15.8 			2.7 		
Balance as of December 31, 2019		$	109.9 			$	37.7 			$	5.8 			$	(103.6)			$	15.8 			$	1.4 		

																																							
Year Ended December 31, 2018		AEP		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Balance as of December 31, 2017		$	40.3 			$	24.7 			$	7.6 			$	(132.4)			$	6.2 			$	5.9 		
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		148.9 			104.1 			14.2 			1.8 			18.1 			(4.8)		
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)		9.8 			— 			— 			— 			— 			— 		
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)		15.7 			— 			— 			— 			— 			— 		
Settlements		(214.0)			(127.9)			(21.3)			4.6 			(24.3)			(2.1)		
Transfers into Level 3 (d) (e)		15.8 			— 			— 			— 			— 			— 		
Transfers out of Level 3 (e)		(1.6)			— 			(0.3)			— 			— 			— 		
Changes in Fair Value Allocated to Regulated Jurisdictions (f)		116.3 			56.9 			8.7 			26.6 			9.5 			3.3 		
Balance as of December 31, 2018		$	131.2 			$	57.8 			$	8.9 			$	(99.4)			$	9.5 			$	2.3 		

(a)Included in revenues on the statements of income.
(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)Included in cash flow hedges on the statements of comprehensive income.
(d)Represents existing assets or liabilities that were previously categorized as Level 2.
(e)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(f)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 assets/liabilities or accounts payable.
344

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:

AEP

December 31, 2020	
					Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input		Low		High		Average	
	(in millions)											
Energy Contracts	$	213.5 			$	169.7 			Discounted Cash Flow		Forward Market Price (a) (c)		$	5.33		$	100.47 			$	32.73	
Natural Gas Contracts	— 			1.7 			Discounted Cash Flow		Forward Market Price (b) (c)		2.18		2.77		2.40	
FTRs	42.8 			3.4 			Discounted Cash Flow		Forward Market Price (a) (c)		(15.08)		9.66		0.19	
Other Investments	31.8 			— 			Black-Scholes Model		Liquidity Adjustment (d)		10 	%		20 	%		15 	%	
Total	$	288.1 			$	174.8 												

																																										
December 31, 2019	
					Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	296.7 			$	249.3 			Discounted Cash Flow		Forward Market Price (a)		$	(0.05)			$	177.30 			$	31.31 		
Natural Gas Contracts	— 			4.9 			Discounted Cash Flow		Forward Market Price (b)		1.89 			2.51 			2.19 		
FTRs	75.7 			8.3 			Discounted Cash Flow		Forward Market Price (a)		(8.52)			9.34 			0.42 		
Total	$	372.4 			$	262.5 												

345

APCo

																																										
December 31, 2020	
							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	1.0 			$	0.6 			Discounted Cash Flow		Forward Market Price		$	10.84 			$	41.09 			$	25.08 		
FTRs	18.9 			— 			Discounted Cash Flow		Forward Market Price		0.04 			5.61 			1.13 		
Total	$	19.9 			$	0.6 												

																																										
December 31, 2019	
							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	5.7 			$	2.6 			Discounted Cash Flow		Forward Market Price		$	12.70 			$	41.20 			$	25.92 		
FTRs	34.8 			0.2 			Discounted Cash Flow		Forward Market Price		(0.14)			7.08 			1.70 		
Total	$	40.5 			$	2.8 												

I&M

																																										
December 31, 2020	
							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	0.6 			$	0.3 			Discounted Cash Flow		Forward Market Price		$	10.84 			$	41.09 			$	25.08 		
FTRs	1.9 			0.1 			Discounted Cash Flow		Forward Market Price		(1.96)			3.69 			0.33 		
Total	$	2.5 			$	0.4 												

																																										
December 31, 2019	
							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	3.4 			$	1.5 			Discounted Cash Flow		Forward Market Price		$	12.70 			$	41.20 			$	25.92 		
FTRs	4.6 			0.7 			Discounted Cash Flow		Forward Market Price		(0.75)			4.07 			0.74 		
Total	$	8.0 			$	2.2 												

346

OPCo

																																										
December 31, 2020	
							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	— 			$	110.3 			Discounted Cash Flow		Forward Market Price		$	16.19 			$	46.98 			$	28.30 		

																																										
December 31, 2019	
							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	— 			$	103.6 			Discounted Cash Flow		Forward Market Price		$	29.23 			$	61.43 			$	42.46 		

PSO

																																										
December 31, 2020	
							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
FTRs	$	10.3 			$	— 			Discounted Cash Flow		Forward Market Price		$	(6.93)			$	0.48 			$	(1.93)		

																																										
December 31, 2019	
							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
FTRs	$	16.3 			$	0.5 			Discounted Cash Flow		Forward Market Price		$	(8.52)			$	0.85 			$	(2.31)		

347

SWEPCo

																																										
December 31, 2020	
							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input		Low		High		Average (c)	
	(in millions)											
Natural Gas Contracts	$	— 			$	1.7 			Discounted Cash Flow		Forward Market Price (b)		$	2.18 			$	2.77 			$	2.41 		
FTRs	3.3 			— 			Discounted Cash Flow		Forward Market Price (a)		(6.93)			0.48 			(1.93)		
Total	$	3.3 			$	1.7 												

																																										
December 31, 2019	
							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input		Low		High		Average (c)	
	(in millions)											
Natural Gas Contracts	$	— 			$	4.9 			Discounted Cash Flow		Forward Market Price (b)		$	1.89 			$	2.51 			$	2.18 		
FTRs	6.5 			0.2 			Discounted Cash Flow		Forward Market Price (a)		(8.52)			0.85 			(2.31)		
Total	$	6.5 			$	5.1 												

(a)Represents market prices in dollars per MWh.
(b)Represents market prices in dollars per MMBtu.
(c)The weighted-average is the product of the forward market price of the underlying commodity and volume weighted by term.
(d)Represents percentage discount applied to the publically available share price.

The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts, FTRs and Other Investments for the Registrants as of December 31, 2020 and 2019:

Uncertainty of Fair Value Measurements

Significant Unobservable Input		Position		Change in Input		Impact on Fair Value
Measurement	
Forward Market Price		Buy		Increase (Decrease)		Higher (Lower)	
Forward Market Price		Sell		Increase (Decrease)		Lower (Higher)	
Liquidity Adjustment		Buy		Increase (Decrease)		Lower (Higher)	

348

12. INCOME TAXES

The disclosures in this note apply to all Registrants unless indicated otherwise.

Income Tax Expense (Benefit)

The details of the Registrants’ Income Tax Expense (Benefit) as reported are as follows:

Year Ended December 31, 2020		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Federal:																	
Current		$	(138.2)			$	5.2 			$	22.2 			$	21.4 			$	11.3 			$	(26.6)			$	(11.4)			$	(13.6)		
Deferred		146.9 			(15.4)			65.4 			(27.1)			(20.6)			74.0 			8.3 			19.6 		
	
Total Federal		8.7 			(10.2)			87.6 			(5.7)			(9.3)			47.4 			(3.1)			6.0 		
																	
State and Local:																	
Current		(16.7)			(0.1)			2.8 			9.3 			1.9 			(5.4)			0.1 			(8.2)		
Deferred		48.5 			(0.9)			16.3 			0.7 			(0.1)			3.2 			8.2 			11.6 		
	
Total State and Local		31.8 			(1.0)			19.1 			10.0 			1.8 			(2.2)			8.3 			3.4 		
																	
Income Tax Expense (Benefit)		$	40.5 			$	(11.2)			$	106.7 			$	4.3 			$	(7.5)			$	45.2 			$	5.2 			$	9.4 		

																																																			
Year Ended December 31, 2019		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Federal:																	
Current		$	(7.4)			$	(31.8)			$	23.7 			$	36.7 			$	48.1 			$	(10.0)			$	25.5 			$	6.9 		
Deferred		(71.6)			(24.7)			71.7 			(126.1)			(57.1)			40.6 			(26.0)			(10.0)		
	
Total Federal		(79.0)			(56.5)			95.4 			(89.4)			(9.0)			30.6 			(0.5)			(3.1)		
																	
State and Local:																	
Current		4.4 			2.9 			2.4 			12.0 			(2.4)			1.1 			0.2 			0.8 		
Deferred		61.7 			— 			19.6 			(0.6)			0.8 			3.2 			7.8 			(2.4)		
	
Total State and Local		66.1 			2.9 			22.0 			11.4 			(1.6)			4.3 			8.0 			(1.6)		
																	
Income Tax Expense (Benefit)		$	(12.9)			$	(53.6)			$	117.4 			$	(78.0)			$	(10.6)			$	34.9 			$	7.5 			$	(4.7)		

																																																			
Year Ended December 31, 2018		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Federal:																	
Current		$	(31.7)			$	37.0 			$	(14.2)			$	(31.9)			$	60.9 			$	55.6 			$	35.6 			$	18.3 		
Deferred		122.0 			(17.9)			82.3 			(24.5)			(48.8)			(36.9)			(36.7)			(1.9)		
	
Total Federal		90.3 			19.1 			68.1 			(56.4)			12.1 			18.7 			(1.1)			16.4 		
																	
State and Local:																	
Current		30.8 			1.8 			(0.6)			3.7 			15.8 			4.6 			(0.2)			2.3 		
Deferred		(5.8)			(0.1)			16.6 			7.8 			1.2 			0.7 			6.3 			1.7 		
	
Total State and Local		25.0 			1.7 			16.0 			11.5 			17.0 			5.3 			6.1 			4.0 		
																	
Income Tax Expense (Benefit)		$	115.3 			$	20.8 			$	84.1 			$	(44.9)			$	29.1 			$	24.0 			$	5.0 			$	20.4 		

349

The following are reconciliations for the Registrants between the federal income taxes computed by multiplying pretax income by the federal statutory tax rate and the income taxes reported:

AEP	Years Ended December 31,	
	2020		2019		2018	
	(in millions)	
Net Income	$	2,196.7 			$	1,919.8 			$	1,931.3 		
Less: Equity Earnings – Dolet Hills	(2.9)			(3.0)			(2.7)		
Income Tax Expense (Benefit)	40.5 			(12.9)			115.3 		
Pretax Income	$	2,234.3 			$	1,903.9 			$	2,043.9 		
						
Income Taxes on Pretax Income at Statutory Rate (21%)	$	469.2 			$	399.8 			$	429.2 		
Increase (Decrease) in Income Taxes Resulting from the Following Items:						
Depreciation	26.5 			20.4 			24.6 		
	
Investment Tax Credit Amortization	(18.8)			(13.0)			(20.4)		
Production Tax Credits	(83.1)			(59.6)			(10.3)		
State and Local Income Taxes, Net	25.1 			52.2 			19.7 		
Removal Costs	(18.6)			(22.2)			(18.6)		
AFUDC	(32.5)			(37.1)			(29.4)		

Tax Reform Adjustments	— 			— 			(10.9)		
	
Tax Reform Excess ADIT Reversal	(268.2)			(353.2)			(257.2)		

CARES Act	(48.0)			— 			— 		
Other	(11.1)			(0.2)			(11.4)		
Income Tax Expense (Benefit)	$	40.5 			$	(12.9)			$	115.3 		
						
Effective Income Tax Rate	1.8 		%		(0.7)		%		5.6 		%	

																											
AEP Texas	Years Ended December 31,	
	2020		2019		2018	
	(in millions)	
Net Income	$	241.0 			$	178.3 			$	211.3 		
Income Tax Expense (Benefit)	(11.2)			(53.6)			20.8 		
Pretax Income	$	229.8 			$	124.7 			$	232.1 		
						
Income Taxes on Pretax Income at Statutory Rate (21%)	$	48.3 			$	26.2 			$	48.7 		
Increase (Decrease) in Income Taxes Resulting from the Following Items:						
Depreciation	1.0 			1.0 			0.7 		
	
Investment Tax Credit Amortization	(1.1)			(1.2)			(2.3)		
	
State and Local Income Taxes, Net	(0.8)			2.3 			1.3 		
	
AFUDC	(4.1)			(3.2)			(4.2)		
Parent Company Loss Benefit	(4.5)			(3.8)			(3.0)		
	
Tax Reform Adjustments	— 			— 			(11.0)		
	
Tax Reform Excess ADIT Reversal	(47.9)			(73.4)			(11.8)		

	
Other	(2.1)			(1.5)			2.4 		
Income Tax Expense (Benefit)	$	(11.2)			$	(53.6)			$	20.8 		
						
Effective Income Tax Rate	(4.9)		%		(43.0)		%		9.0 		%	
350

																											
AEPTCo	Years Ended December 31,	
	2020		2019		2018	
	(in millions)	
Net Income	$	423.4 			$	439.7 			$	315.9 		
Income Tax Expense	106.7 			117.4 			84.1 		
Pretax Income	$	530.1 			$	557.1 			$	400.0 		
						
Income Taxes on Pretax Income at Statutory Rate (21%)	$	111.3 			$	117.0 			$	84.0 		
Increase (Decrease) in Income Taxes Resulting from the Following Items:						

	
	
State and Local Income Taxes, Net	15.1 			17.4 			12.6 		
	
AFUDC	(15.5)			(17.7)			(14.1)		
Parent Company Loss Benefit	(7.0)			(4.2)			(0.6)		

	

	
	
Other	2.8 			4.9 			2.2 		
Income Tax Expense	$	106.7 			$	117.4 			$	84.1 		
						
Effective Income Tax Rate	20.1 		%		21.1 		%		21.0 		%	

																											
APCo	Years Ended December 31,	
	2020		2019		2018	
	(in millions)	
Net Income	$	369.7 			$	306.3 			$	367.8 		
Income Tax Expense (Benefit)	4.3 			(78.0)			(44.9)		
Pretax Income	$	374.0 			$	228.3 			$	322.9 		
						
Income Taxes on Pretax Income at Statutory Rate (21%)	$	78.5 			$	47.9 			$	67.8 		
Increase (Decrease) in Income Taxes Resulting from the Following Items:						
Depreciation	12.7 			10.8 			9.4 		

	
State and Local Income Taxes, Net	7.9 			9.0 			9.1 		
Removal Costs	(5.7)			(6.4)			(7.9)		
AFUDC	(4.5)			(5.2)			(4.3)		
Parent Company Loss Benefit	(6.2)			(4.1)			(3.6)		

	
Tax Reform Excess ADIT Reversal	(72.3)			(130.4)			(108.5)		
	
Federal Return to Provision	(7.2)			(1.0)			(6.6)		
	
Other	1.1 			1.4 			(0.3)		
Income Tax Expense (Benefit)	$	4.3 			$	(78.0)			$	(44.9)		
						
Effective Income Tax Rate	1.1 		%		(34.2)		%		(13.9)		%	

351

																											
I&M	Years Ended December 31,	
	2020		2019		2018	
	(in millions)	
Net Income	$	284.8 			$	269.4 			$	261.3 		
Income Tax Expense (Benefit)	(7.5)			(10.6)			29.1 		
Pretax Income	$	277.3 			$	258.8 			$	290.4 		
						
Income Taxes on Pretax Income at Statutory Rate (21%)	$	58.2 			$	54.3 			$	61.0 		
Increase (Decrease) in Income Taxes Resulting from the Following Items:						
Depreciation	1.6 			4.0 			1.5 		
	
Investment Tax Credit Amortization	(4.5)			(3.6)			(4.7)		
	
State and Local Income Taxes, Net	1.5 			(1.2)			13.4 		
Removal Costs	(10.5)			(12.8)			(8.0)		
AFUDC	(2.4)			(4.1)			(2.5)		
Parent Company Loss Benefit	(6.4)			(3.3)			(2.3)		

	
Tax Reform Excess ADIT Reversal	(46.8)			(42.5)			(25.8)		
	
Federal Return to Provision	1.9 			(0.3)			(4.6)		
	
Other	(0.1)			(1.1)			1.1 		
Income Tax Expense (Benefit)	$	(7.5)			$	(10.6)			$	29.1 		
						
Effective Income Tax Rate	(2.7)		%		(4.1)		%		10.0 		%	

																											
OPCo	Years Ended December 31,	
	2020		2019		2018	
	(in millions)	
Net Income	$	271.4 			$	297.1 			$	325.5 		
Income Tax Expense	45.2 			34.9 			24.0 		
Pretax Income	$	316.6 			$	332.0 			$	349.5 		
						
Income Taxes on Pretax Income at Statutory Rate (21%)	$	66.5 			$	69.7 			$	73.4 		
Increase (Decrease) in Income Taxes Resulting from the Following Items:						
Depreciation	3.7 			(1.4)			2.4 		

	
State and Local Income Taxes, Net	(1.7)			3.4 			4.2 		
	
AFUDC	(2.6)			(3.8)			(2.1)		
Parent Company Loss Benefit	— 			(1.8)			(6.0)		

	
Tax Reform Excess ADIT Reversal	(27.2)			(27.3)			(51.0)		
	
Federal Return to Provision	6.5 			(3.7)			0.2 		
	
Other	— 			(0.2)			2.9 		
Income Tax Expense	$	45.2 			$	34.9 			$	24.0 		
						
Effective Income Tax Rate	14.3 		%		10.5 		%		6.9 		%	
352

																											
PSO	Years Ended December 31,	
	2020		2019		2018	
	(in millions)	
Net Income	$	123.0 			$	137.6 			$	83.2 		
Income Tax Expense	5.2 			7.5 			5.0 		
Pretax Income	$	128.2 			$	145.1 			$	88.2 		
						
Income Taxes on Pretax Income at Statutory Rate (21%)	$	26.9 			$	30.5 			$	18.5 		
Increase (Decrease) in Income Taxes Resulting from the Following Items:						
Depreciation	1.1 			0.6 			0.7 		
	
Investment Tax Credit Amortization	(2.1)			(0.5)			(1.7)		
	
State and Local Income Taxes, Net	6.5 			6.3 			4.8 		

Parent Company Loss Benefit	(0.2)			(2.1)			(1.4)		

	
Tax Reform Excess ADIT Reversal	(25.5)			(24.5)			(15.5)		

	
Other	(1.5)			(2.8)			(0.4)		
Income Tax Expense	$	5.2 			$	7.5 			$	5.0 		
						
Effective Income Tax Rate	4.1 		%		5.2 		%		5.7 		%	

																											
SWEPCo	Years Ended December 31,	
	2020		2019		2018	
	(in millions)	
Net Income	$	183.7 			$	162.2 			$	152.2 		
Less: Equity Earnings – Dolet Hills	(2.9)			(3.0)			(2.7)		
Income Tax Expense (Benefit)	9.4 			(4.7)			20.4 		
Pretax Income	$	190.2 			$	154.5 			$	169.9 		
						
Income Taxes on Pretax Income at Statutory Rate (21%)	$	39.9 			$	32.4 			$	35.7 		
Increase (Decrease) in Income Taxes Resulting from the Following Items:						
Depreciation	1.9 			1.9 			1.9 		
Depletion	(3.4)			(3.4)			(3.4)		

State and Local Income Taxes, Net	2.7 			(1.3)			3.2 		
	
AFUDC	(1.5)			(1.4)			(1.3)		
Parent Company Loss Benefit	(5.6)			(1.6)			(0.6)		

	
Tax Reform Excess ADIT Reversal	(21.9)			(29.9)			(16.0)		

	
Other	(2.7)			(1.4)			0.9 		
Income Tax Expense (Benefit)	$	9.4 			$	(4.7)			$	20.4 		
						
Effective Income Tax Rate	4.9 		%		(3.0)		%		12.0 		%	
353

Net Deferred Tax Liability

The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant:

AEP	December 31,	
	2020		2019	
	(in millions)	
Deferred Tax Assets	$	3,259.7 			$	3,246.1 		
Deferred Tax Liabilities	(11,500.6)			(10,834.3)		
Net Deferred Tax Liabilities	$	(8,240.9)			$	(7,588.2)		
				
Property Related Temporary Differences	$	(7,340.5)			$	(6,602.9)		
Amounts Due to Customers for Future Income Taxes	1,075.8 			1,173.5 		
Deferred State Income Taxes	(1,317.6)			(1,198.0)		
	
Securitized Assets	(140.0)			(178.7)		
	
Regulatory Assets	(391.6)			(371.1)		
	
Accrued Nuclear Decommissioning	(626.4)			(557.4)		
Net Operating Loss Carryforward	112.9 			77.6 		
Tax Credit Carryforward	323.6 			247.2 		
Operating Lease Liability	183.7 			182.6 		
Investment in Partnership	(362.0)			(446.6)		

	
	
All Other, Net	241.2 			85.6 		
Net Deferred Tax Liabilities	$	(8,240.9)			$	(7,588.2)		

												
AEP Texas	December 31,	
	2020		2019	
	(in millions)	
Deferred Tax Assets	$	183.6 			$	220.0 		
Deferred Tax Liabilities	(1,200.3)			(1,185.4)		
Net Deferred Tax Liabilities	$	(1,016.7)			$	(965.4)		
				
Property Related Temporary Differences	$	(1,039.6)			$	(973.5)		
Amounts Due to Customers for Future Income Taxes	114.4 			126.7 		
Deferred State Income Taxes	(29.1)			(27.5)		

Securitized Transition Assets	(90.2)			(124.3)		
Regulatory Assets	(47.4)			(51.2)		

	
	
Operating Lease Liability	18.0 			17.2 		

	

All Other, Net	57.2 			67.2 		
Net Deferred Tax Liabilities	$	(1,016.7)			$	(965.4)		

												
AEPTCo	December 31,	
	2020		2019	
	(in millions)	
Deferred Tax Assets	$	166.5 			$	162.9 		
Deferred Tax Liabilities	(1,073.4)			(980.7)		
Net Deferred Tax Liabilities	$	(906.9)			$	(817.8)		
				
Property Related Temporary Differences	$	(937.8)			$	(847.1)		
Amounts Due to Customers for Future Income Taxes	118.9 			119.9 		
Deferred State Income Taxes	(98.3)			(86.1)		

	

	
Net Operating Loss Carryforward	13.2 			12.3 		

	

	
	
All Other, Net	(2.9)			(16.8)		
Net Deferred Tax Liabilities	$	(906.9)			$	(817.8)		

354

												
APCo	December 31,	
	2020		2019	
	(in millions)	
Deferred Tax Assets	$	500.6 			$	486.2 		
Deferred Tax Liabilities	(2,250.5)			(2,167.0)		
Net Deferred Tax Liabilities	$	(1,749.9)			$	(1,680.8)		
				
Property Related Temporary Differences	$	(1,412.0)			$	(1,420.0)		
Amounts Due to Customers for Future Income Taxes	198.3 			222.8 		
Deferred State Income Taxes	(336.5)			(337.2)		
	
Securitized Assets	(44.7)			(49.3)		
	
Regulatory Assets	(114.8)			(71.0)		

	
	
Operating Lease Liability	16.7 			16.5 		

	

All Other, Net	(56.9)			(42.6)		
Net Deferred Tax Liabilities	$	(1,749.9)			$	(1,680.8)		

												
I&M	December 31,	
	2020		2019	
	(in millions)	
Deferred Tax Assets	$	989.5 			$	970.5 		
Deferred Tax Liabilities	(2,053.9)			(1,950.2)		
Net Deferred Tax Liabilities	$	(1,064.4)			$	(979.7)		
				
Property Related Temporary Differences	$	(409.2)			$	(430.7)		
Amounts Due to Customers for Future Income Taxes	147.9 			169.6 		
Deferred State Income Taxes	(211.1)			(194.4)		

	
Regulatory Assets	(16.5)			(26.9)		
	
Accrued Nuclear Decommissioning	(626.4)			(557.4)		

Operating Lease Liability	46.6 			61.9 		

	

All Other, Net	4.3 			(1.8)		
Net Deferred Tax Liabilities	$	(1,064.4)			$	(979.7)		

												
OPCo	December 31,	
	2020		2019	
	(in millions)	
Deferred Tax Assets	$	210.8 			$	202.3 		
Deferred Tax Liabilities	(1,165.9)			(1,051.6)		
Net Deferred Tax Liabilities	$	(955.1)			$	(849.3)		
				
Property Related Temporary Differences	$	(1,016.0)			$	(890.8)		
Amounts Due to Customers for Future Income Taxes	121.1 			130.2 		
Deferred State Income Taxes	(40.7)			(35.5)		

	
Regulatory Assets	(53.7)			(48.0)		

	
	
Operating Lease Liability	19.4 			18.3 		

	

All Other, Net	14.8 			(23.5)		
Net Deferred Tax Liabilities	$	(955.1)			$	(849.3)		

355

												
PSO	December 31,	
	2020		2019	
	(in millions)	
Deferred Tax Assets	$	239.8 			$	257.4 		
Deferred Tax Liabilities	(928.3)			(885.7)		
Net Deferred Tax Liabilities	$	(688.5)			$	(628.3)		
				
Property Related Temporary Differences	$	(661.8)			$	(627.6)		
Amounts Due to Customers for Future Income Taxes	118.5 			127.2 		
Deferred State Income Taxes	(107.7)			(100.4)		

	
Regulatory Assets	(39.1)			(44.6)		

Net Operating Loss Carryforward	12.9 			10.2 		

	

	
	
All Other, Net	(11.3)			6.9 		
Net Deferred Tax Liabilities	$	(688.5)			$	(628.3)		

												
SWEPCo	December 31,	
	2020		2019	
	(in millions)	
Deferred Tax Assets	$	338.1 			$	359.6 		
Deferred Tax Liabilities	(1,355.7)			(1,300.5)		
Net Deferred Tax Liabilities	$	(1,017.6)			$	(940.9)		
				
Property Related Temporary Differences	$	(985.1)			$	(947.6)		
Amounts Due to Customers for Future Income Taxes	162.7 			169.8 		
Deferred State Income Taxes	(214.7)			(200.3)		

	
Regulatory Assets	(26.2)			(30.2)		

Net Operating Loss Carryforward	33.4 			38.2 		

	

	
	
All Other, Net	12.3 			29.2 		
Net Deferred Tax Liabilities	$	(1,017.6)			$	(940.9)		

AEP System Tax Allocation Agreement

AEP and subsidiaries join in the filing of a consolidated federal income tax return.  The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries with taxable income reducing their current tax expense proportionately.  The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable losses. With the exception of the allocation of the consolidated AEP System NOL, the loss of the Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.

Federal Income Tax Audit Status

The statute of limitations for the IRS to examine AEP and subsidiaries originally filed federal return has expired for tax years 2016 and earlier. In the third quarter of 2019, AEP and subsidiaries elected to amend the 2014 and 2015 federal returns. In the first quarter of 2020, the IRS notified AEP that it was beginning an examination of these amended returns, including the NOL carryback to 2015 that originated in the 2017 return. As of December 31, 2020, the IRS has not challenged any items on these returns and the IRS is limited in their proposed adjustments to the amount AEP claimed on the amended returns.

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Net Income Tax Operating Loss Carryforward

As of December 31, 2020, AEP has no federal net income tax operating loss carryforward. AEP, AEPTCo, I&M, PSO and SWEPCo have state net income tax operating loss carryforwards as indicated in the table below:

				State Net Income					
				 Tax Operating Loss		Years of	
Company		State/Municipality		Carryforward		Expiration	
				(in millions)					
AEP		Arkansas		$	87.2 			2021	-	2028	
AEP		Kentucky		163.7 			2030	-	2037	
AEP		Louisiana		466.8 			2025	-	2040	
AEP		Oklahoma		569.4 			2034	-	2037	
AEP		Tennessee		31.1 			2028	-	2035	
AEP		Virginia		29.4 			2025	-	2037	
AEP		West Virginia		21.9 			2029	-	2037	
AEP		Ohio Municipal		649.8 			2021	-	2025	
AEP		Indiana		145.7 			2039	
AEP		Colorado		95.7 			NA	
AEP		Pennsylvania		56.5 			2030	-	2040	
AEP		New Jersey		60.2 			2036	-	2040	
AEP		Illinois		15.6 			2031	
AEP		Michigan		14.9 			2029	
AEPTCo		Oklahoma		195.4 			2034	-	2037	
AEPTCo		Ohio Municipal		18.4 			2023	
I&M		West Virginia		2.5 			2032	-	2037	
PSO		Oklahoma		354.5 			2034	-	2037	
SWEPCo		Arkansas		86.4 			2021	-	2024	
SWEPCo		Louisiana		454.3 			2032	-	2037	

As of December 31, 2020, AEP recorded a valuation allowance of $9 million, against certain state and municipal net income tax operating loss carryforwards since future taxable income is not expected to be sufficient to realize the remaining state net income tax operating loss tax benefits before the carryforward expires. Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the carryforward expires for each state.

Tax Credit Carryforward

Federal and state net income tax operating losses sustained in 2016, 2017 and 2019 resulted in unused federal and state income tax credits.  As of December 31, 2020, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below.  If these credits are not utilized, federal general business tax credits will expire in the years 2036 through 2040 and state tax credits will remain available indefinitely.

	
		Total Federal		Total State	
		Tax Credit		Tax Credit	
Company		Carryforward		Carryforward	
		(in millions)	
AEP		$	323.6 			$	38.4 		
AEP Texas		1.2 			— 		
AEPTCo		0.1 			— 		
APCo		1.6 			— 		
I&M		9.7 			— 		
OPCo		0.5 			— 		
PSO		0.5 			38.4 		
SWEPCo		1.3 			— 		

The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused.
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Valuation Allowance

AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective evidence evaluated includes whether AEP has a history of recognizing income, future reversals of existing temporary differences and tax planning strategies.

Valuation allowance activity for the years ended December 31, 2020, 2019 and 2018 was immaterial.

Uncertain Tax Positions

The reconciliations of the beginning and ending amounts of unrecognized tax benefits for AEP are presented below. The amount and activity of unrecognized tax benefits for Registrants Subsidiaries was immaterial for periods presented:

		AEP	
		2020		2019		2018	
		(in millions)	
Balance as of January 1,		$	24.1 			$	14.6 			$	86.6 		
Increase – Tax Positions Taken During a Prior Period		0.6 			8.8 			0.1 		
Decrease – Tax Positions Taken During a Prior Period		(14.5)			(2.1)			— 		
Increase – Tax Positions Taken During the Current Year		3.0 			2.8 			— 		
Decrease – Tax Positions Taken During the Current Year		— 			— 			— 		
	
Decrease – Settlements with Taxing Authorities		— 			— 			(71.0)		
Decrease – Lapse of the Applicable Statute of Limitations		— 			— 			(1.1)		
Balance as of December 31,		$	13.2 			$	24.1 			$	14.6 		

Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date.  The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for AEP as of December 31, 2020, 2019 and 2018 were $12 million, $20 million and $12 million, respectively.

Federal Tax Legislation

In March 2020, the CARES Act was signed into law. The CARES Act includes tax relief provisions such as: (a) an AMT Credit Refund, (b) a 5-year NOL carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. Pursuant to the CARES Act, AEP, APCo and OPCo requested and in July received refunds of AMT credit of $20 million, $7 million and $9 million, respectively. In the third quarter of 2020, AEP also requested a $95 million refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. AEP carried back a NOL generated on the 2019 Federal income tax return at a 21% federal corporate income tax rate to the 2014 Federal income tax return at a 35% corporate income tax rate. As a result of the change in the corporate income tax rates between the two periods, AEP realized a tax benefit of $48 million primarily at the Generation & Marketing segment. Management will continue to monitor potential legislation and any impacts to the AMT Credit and NOL refunds that were filed in 2020 pursuant to the CARES Act.

In December 2020, the CAA of 2021 was signed into law. The CAA of 2021 includes: (a) COVID-19 tax relief and tax extender provisions including extensions of time to begin construction on and placed in-service assets generating PTCs and ITCs, (b) 100% deductibility of business meals in 2021 and 2022 and (c) an extension of the work opportunity tax credit. The ITC percentage has been increased for projects starting construction through 2023 and placed in-service by the end of 2025. The PTC has been extended for an additional year, to include projects started in 2021 and completed in 2025. These provisions provide time and flexibility on the construction start and in-service dates.
358

In September and November 2020, the IRS issued final regulations that provide guidance regarding the additional first-year depreciation deduction under Section 168(k). The final regulations reflect changes as a result of Tax Reform, which affects taxpayers with qualified depreciable property acquired and placed in-service after September 27, 2017. Generally, AEP’s regulated utilities will not be eligible for any bonus depreciation for property acquired and placed in-service after December 31, 2017. AEP’s competitive businesses will be eligible for 100% expensing.

The IRS issued final regulations in 2020 that provide guidance concerning potential limitations on the deduction of business interest expense. These regulations require an allocation of net interest expense between regulated and competitive businesses within the consolidated tax return. This allocation is based upon net tax basis, and the proposed regulations provide de minimis tests under which all interest is deductible if less than 10% is allocable to the competitive businesses. AEP will deduct materially all business interest expense under this de minimis provision.

On December 30, 2020, the IRS issued regulations that provide guidance on the non-deductibility of certain executives compensation above $1 million under Internal Revenue Code Section 162(m). The regulations clarify the application of rules passed under Tax Reform that expanded the application of Section 162(m) to SEC registered companies that issue either public equity or debt. These rules also expanded the type of compensation and the number of executives subject to this deduction disallowance. AEP limits certain executives’ compensation to the $1 million limitation on its federal income tax return.
359

13.  LEASES

The disclosures in this note apply to all Registrants unless indicated otherwise. Management adopted ASU 2016-02 effective January 1, 2019 by means of a cumulative-effect adjustment to the balance sheets.

The Registrants lease property, plant and equipment including, but not limited to, fleet, information technology and real estate leases. These leases require payments of non-lease components, including related property taxes, operating and maintenance costs. AEP does not separate non-lease components from associated lease components. Many of these leases have purchase or renewal options. Leases not renewed are often replaced by other leases. Options to renew or purchase a lease are included in the measurement of lease assets and liabilities if it is reasonably certain the Registrant will exercise the option.

Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. AEP has visibility into the rate implicit in the lease when assets are leased from selected financial institutions under master leasing agreements. When the implicit rate is not readily determinable, the Registrants measure their lease obligation using their estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk-free rate and a secured credit spread relative to the lessee on a matched maturity basis.

Operating lease rentals and finance lease amortization costs are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Effective in 2019, interest on finance lease liabilities is generally charged to Interest Expense. Finance lease interest for periods prior to 2019 were charged to Other Operation and Maintenance expense. Lease costs associated with capital projects are included in Property, Plant and Equipment on the balance sheets. For regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period.  Finance leases for nonregulated property are accounted for as if the assets were owned and financed.  The components of rental costs were as follows:

Year Ended December 31, 2020		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Operating Lease Cost		$	279.6 			$	17.4 			$	2.6 			$	19.1 			$	101.5 			$	17.1 			$	7.8 			$	9.4 		
Finance Lease Cost:																	
Amortization of Right-of-Use Assets		61.9 			6.3 			— 			7.4 			6.5 			4.7 			3.5 			10.9 		
Interest on Lease Liabilities		15.4 			1.5 			— 			2.7 			3.1 			0.9 			0.7 			2.2 		
Total Lease Rental Costs (a)		$	356.9 			$	25.2 			$	2.6 			$	29.2 			$	111.1 			$	22.7 			$	12.0 			$	22.5 		

Year Ended December 31, 2019		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Operating Lease Cost		$	286.0 			$	16.5 			$	2.5 			$	19.5 			$	93.1 			$	18.0 			$	6.8 			$	8.0 		
Finance Lease Cost:																	
Amortization of Right-of-Use Assets		70.8 			5.1 			0.1 			6.7 			5.7 			3.5 			3.1 			11.0 		
Interest on Lease Liabilities		16.4 			1.4 			— 			2.9 			2.9 			0.7 			0.6 			2.9 		
Total Lease Rental Costs (a)		$	373.2 			$	23.0 			$	2.6 			$	29.1 			$	101.7 			$	22.2 			$	10.5 			$	21.9 		

Year Ended December 31, 2018		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Operating Lease Cost		$	245.0 			$	13.6 			$	2.7 			$	18.2 			$	89.2 			$	10.7 			$	5.7 			$	6.5 		
Finance Lease Cost:																	
Amortization of Right-of-Use Assets		62.4 			4.8 			0.1 			7.0 			6.6 			3.9 			3.2 			11.2 		
Interest on Lease Liabilities		16.4 			1.2 			— 			3.0 			3.3 			0.5 			0.4 			3.2 		
Total Lease Rental Costs		$	323.8 			$	19.6 			$	2.8 			$	28.2 			$	99.1 			$	15.1 			$	9.3 			$	20.9 		

(a)Excludes variable and short-term lease costs, which were immaterial for the twelve months ended December 31, 2020 and December 31, 2019.

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Supplemental information related to leases are shown in the tables below:

December 31, 2020		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
Weighted-Average Remaining Lease Term (years):																	
Operating Leases		5.30		6.51		2.01		6.27		3.50		7.44		7.03		7.54	
Finance Leases		5.43		6.07		0.00		5.75		5.79		5.90		6.16		4.95	
Weighted-Average Discount Rate:																	
Operating Leases		3.44 	%		3.60 	%		1.51 	%		3.48 	%		3.42 	%		3.60 	%		3.39 	%		3.45 	%	
Finance Leases		5.68 	%		4.39 	%		— 	%		7.33 	%		8.29 	%		4.25 	%		4.35 	%		4.77 	%	

December 31, 2019		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
Weighted-Average Remaining Lease Term (years):																	
Operating Leases		5.23		6.93		2.25		6.28		3.91		7.94		7.07		6.64	
Finance Leases		5.85		6.69		0.25		6.12		6.55		6.49		6.23		5.16	
Weighted-Average Discount Rate:																	
Operating Leases		3.60 	%		3.77 	%		3.14 	%		3.64 	%		3.45 	%		3.76 	%		3.64 	%		3.76 	%	
Finance Leases		5.98 	%		4.62 	%		9.33 	%		8.08 	%		8.47 	%		4.54 	%		4.62 	%		5.01 	%	

																																																			
Year Ended December 31, 2020		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Cash paid for amounts included in the measurement of lease liabilities:																	
Operating Cash Flows Used for Operating Leases		$	280.3 			$	17.1 			$	2.6 			$	19.2 			$	102.2 			$	16.9 			$	7.7 			$	9.4 		
Operating Cash Flows Used for Finance Leases		15.4 			1.5 			— 			2.7 			3.1 			0.9 			0.7 			2.2 		
Financing Cash Flows Used for Finance Leases		61.7 			6.3 			— 			7.4 			6.5 			4.7 			3.5 			10.9 		
																	
Non-cash Acquisitions Under Operating Leases		$	161.7 			$	15.8 			$	1.8 			$	16.2 			$	18.1 			$	18.1 			$	12.3 			$	18.4 		

Year Ended December 31, 2019		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Cash paid for amounts included in the measurement of lease liabilities:																	
Operating Cash Flows Used for Operating Leases		$	284.7 			$	15.3 			$	2.4 			$	19.0 			$	94.3 			$	18.0 			$	6.7 			$	7.9 		
Operating Cash Flows Used for Finance Leases		16.4 			1.4 			— 			2.9 			3.1 			0.7 			0.6 			3.0 		
Financing Cash Flows Used for Finance Leases		70.7 			5.1 			— 			6.7 			5.7 			3.5 			3.1 			11.0 		
																	
Non-cash Acquisitions Under Operating Leases		$	125.0 			$	13.8 			$	0.6 			$	10.2 			$	18.7 			$	35.4 			$	8.2 			$	11.4 		

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The following tables show property, plant and equipment under finance leases and noncurrent assets under operating leases and related obligations recorded on the balance sheets.  Unless shown as a separate line on the balance sheets due to materiality, net operating lease assets are included in Deferred Charges and Other Noncurrent Assets, current finance lease obligations are included in Other Current Liabilities and long-term finance lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. Lease obligations are not recognized on the balance sheets for lease agreements with a lease term of less than twelve months.

December 31, 2020		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Property, Plant and Equipment Under Finance Leases:																	
Generation		$	138.2 			$	— 			$	— 			$	42.8 			$	28.8 			$	— 			$	0.7 			$	37.7 		
Other Property, Plant and Equipment		322.8 			49.7 			— 			20.3 			40.2 			31.4 			23.0 			52.4 		
Total Property, Plant and Equipment		461.0 			49.7 			— 			63.1 			69.0 			31.4 			23.7 			90.1 		
Accumulated Amortization		176.8 			16.6 			— 			21.4 			27.3 			9.8 			8.7 			36.5 		
Net Property, Plant and Equipment Under Finance Leases		$	284.2 			$	33.1 			$	— 			$	41.7 			$	41.7 			$	21.6 			$	15.0 			$	53.6 		
																	
Obligations Under Finance Leases:																	
Noncurrent Liability		$	231.0 			$	26.8 			$	— 			$	34.4 			$	35.3 			$	16.9 			$	11.9 			$	44.6 		
Liability Due Within One Year		58.1 			6.3 			— 			7.3 			6.4 			4.7 			3.1 			10.7 		
Total Obligations Under Finance Leases		$	289.1 			$	33.1 			$	— 			$	41.7 			$	41.7 			$	21.6 			$	15.0 			$	55.3 		

																																																			
December 31, 2019		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Property, Plant and Equipment Under Finance Leases:																	
Generation		$	131.6 			$	— 			$	— 			$	39.9 			$	28.8 			$	— 			$	0.6 			$	34.1 		
Other Property, Plant and Equipment		323.0 			45.9 			0.2 			18.9 			39.3 			27.3 			21.6 			51.6 		
Total Property, Plant and Equipment		454.6 			45.9 			0.2 			58.8 			68.1 			27.3 			22.2 			85.7 		
Accumulated Amortization		151.5 			11.8 			0.2 			17.0 			23.0 			7.2 			7.1 			28.4 		
Net Property, Plant and Equipment Under Finance Leases		$	303.1 			$	34.1 			$	— 			$	41.8 			$	45.1 			$	20.1 			$	15.1 			$	57.3 		
																	
Obligations Under Finance Leases:																	
Noncurrent Liability		$	249.2 			$	28.2 			$	— 			$	35.0 			$	38.8 			$	16.2 			$	11.9 			$	47.1 		
Liability Due Within One Year		57.6 			5.9 			— 			6.8 			6.3 			3.9 			3.2 			10.5 		
Total Obligations Under Finance Leases		$	306.8 			$	34.1 			$	— 			$	41.8 			$	45.1 			$	20.1 			$	15.1 			$	57.6 		

362

																																																			
December 31, 2020		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Operating Lease Assets		$	866.4 			$	84.1 			$	1.6 			$	78.8 			$	218.1 			$	92.0 			$	42.6 			$	48.5 		
																	
Obligations Under Operating Leases:																	
Noncurrent Liability		$	638.4 			$	71.0 			$	0.4 			$	64.4 			$	135.9 			$	79.5 			$	36.2 			$	44.1 		
Liability Due Within One Year		241.3 			14.5 			1.2 			14.9 			85.6 			13.1 			6.5 			7.9 		
Total Obligations Under Operating Leases		$	879.7 			$	85.5 			$	1.6 			$	79.3 			$	221.5 			$	92.6 			$	42.7 			$	52.0 		

December 31, 2019		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Operating Lease Assets		$	957.4 			$	81.8 			$	3.8 			$	78.5 			$	294.9 			$	88.0 			$	36.8 			$	40.5 		
																	
Obligations Under Operating Leases:																	
Noncurrent Liability		$	734.6 			$	71.1 			$	1.9 			$	64.0 			$	211.6 			$	76.0 			$	31.0 			$	34.7 		
Liability Due Within One Year		234.1 			12.0 			2.1 			15.2 			87.3 			12.5 			5.8 			6.5 		
Total Obligations Under Operating Leases		$	968.7 			$	83.1 			$	4.0 			$	79.2 			$	298.9 			$	88.5 			$	36.8 			$	41.2 		

Future minimum lease payments consisted of the following as of December 31, 2020:

Finance Leases		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
2021		$	72.2 			$	7.6 			$	— 			$	9.9 			$	9.3 			$	5.5 			$	3.6 			$	13.1 		
2022		64.0 			6.9 			— 			9.4 			8.6 			4.6 			3.1 			11.8 		
2023		56.2 			6.2 			— 			8.7 			7.9 			3.9 			2.7 			10.9 		
2024		63.5 			5.4 			— 			8.1 			11.1 			3.3 			2.3 			15.3 		
2025		32.7 			4.0 			— 			7.0 			5.5 			2.2 			1.6 			5.7 		
Later Years		48.9 			7.8 			— 			6.4 			12.2 			4.9 			3.8 			5.8 		
Total Future Minimum Lease Payments		337.5 			37.9 			— 			49.5 			54.6 			24.4 			17.1 			62.6 		
Less: Imputed Interest		48.4 			4.8 			— 			7.8 			12.9 			2.8 			2.1 			7.3 		
Estimated Present Value of Future Minimum Lease Payments		$	289.1 			$	33.1 			$	— 			$	41.7 			$	41.7 			$	21.6 			$	15.0 			$	55.3 		

																																																			
Operating Leases		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
2021		$	270.8 			$	17.5 			$	1.2 			$	17.7 			$	92.5 			$	16.6 			$	7.9 			$	10.1 		
2022		263.3 			16.4 			0.2 			17.0 			92.5 			16.0 			7.6 			9.6 		
2023		94.2 			14.8 			0.1 			14.2 			11.4 			14.9 			7.3 			8.4 		
2024		81.6 			13.3 			0.1 			11.3 			10.0 			13.2 			6.5 			6.9 		
2025		68.0 			10.9 			— 			8.5 			8.9 			11.5 			5.4 			5.8 		
Later Years		193.0 			23.9 			— 			20.0 			21.8 			34.0 			13.3 			17.4 		
Total Future Minimum Lease Payments		970.9 			96.8 			1.6 			88.7 			237.1 			106.2 			48.0 			58.2 		
Less: Imputed Interest		91.2 			11.3 			— 			9.4 			15.6 			13.6 			5.3 			6.2 		
Estimated Present Value of Future Minimum Lease Payments		$	879.7 			$	85.5 			$	1.6 			$	79.3 			$	221.5 			$	92.6 			$	42.7 			$	52.0 		
363

Future minimum lease payments consisted of the following as of December 31, 2019:

Finance Leases		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
2020		$	72.7 			$	7.3 			$	— 			$	9.6 			$	9.4 			$	4.7 			$	3.8 			$	12.9 		
2021		64.9 			6.7 			— 			8.9 			8.7 			4.3 			3.2 			11.9 		
2022		56.4 			6.0 			— 			8.2 			8.0 			3.4 			2.6 			10.6 		
2023		49.6 			5.4 			— 			7.7 			7.5 			2.8 			2.3 			9.8 		
2024		57.4 			4.6 			— 			7.1 			10.8 			2.4 			1.8 			14.2 		
Later Years		64.4 			9.8 			— 			9.8 			16.4 			5.7 			3.8 			6.8 		
Total Future Minimum Lease Payments		365.4 			39.8 			— 			51.3 			60.8 			23.3 			17.5 			66.2 		
Less: Imputed Interest		58.6 			5.7 			— 			9.5 			15.7 			3.2 			2.4 			8.6 		
Estimated Present Value of Future Minimum Lease Payments		$	306.8 			$	34.1 			$	— 			$	41.8 			$	45.1 			$	20.1 			$	15.1 			$	57.6 		

																																																			
Operating Leases		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
2020		$	269.9 			$	16.0 			$	2.2 			$	18.3 			$	97.0 			$	16.2 			$	7.3 			$	8.6 		
2021		253.6 			15.3 			1.2 			15.7 			92.9 			14.2 			6.4 			8.2 		
2022		245.6 			14.2 			0.6 			14.7 			92.8 			13.5 			6.0 			7.6 		
2023		74.8 			13.0 			0.1 			11.9 			10.1 			12.3 			5.6 			6.4 		
2024		62.0 			11.4 			— 			9.0 			8.6 			10.7 			4.8 			5.0 		
Later Years		169.7 			26.0 			— 			20.0 			21.0 			36.5 			12.0 			11.8 		
Total Future Minimum Lease Payments		1,075.6 			95.9 			4.1 			89.6 			322.4 			103.4 			42.1 			47.6 		
Less: Imputed Interest		106.9 			12.8 			0.1 			10.4 			23.5 			14.9 			5.3 			6.4 		
Estimated Present Value of Future Minimum Lease Payments		$	968.7 			$	83.1 			$	4.0 			$	79.2 			$	298.9 			$	88.5 			$	36.8 			$	41.2 		

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 December 31, 2020, 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		$	50.3 		
AEP Texas		11.7 		
APCo		6.6 		
I&M		4.4 		
OPCo		8.1 		
PSO		4.8 		
SWEPCo		5.4 		

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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. In the first quarter of 2019, in accordance with ASU 2016-02, the $37 million unamortized gain ($15 million related to I&M) associated with the sale-and-leaseback of the Plant was recognized as an adjustment to equity.  The adjustment to equity was then reclassified to regulatory liabilities in accordance with accounting guidance for “Regulated Operations” as AEGCo and I&M will continue to provide the benefit of the unamortized gain to customers in future periods.

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.  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. In November 2020, management announced that AEP will not renew the lease 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 December 31, 2020 were as follows:

															
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.

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 December 31, 2020, the maximum potential amount of future payments required under the guaranteed leases was $48 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 December 31, 2020, AEP’s boat and barge lease guarantee liability was $3 million, of which $1 million was recorded in Other Current Liabilities and $2 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.

In February 2020, the nonaffiliated party filed Chapter 11 bankruptcy. The party entered into a restructuring support agreement and has announced it expects 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.

Lessor Activity

The Registrants’ lessor activity was immaterial as of and for the twelve months ended December 31, 2020 and December 31, 2019, respectively.
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14.  FINANCING ACTIVITIES

The disclosures in this note apply to all Registrants, unless indicated otherwise.

Common Stock (Applies to AEP)

The following table is a reconciliation of common stock share activity:

Shares of AEP Common Stock		Issued		Held in Treasury		
Balance, December 31, 2017		512,210,644 			20,205,046 			
Issued		1,239,392 			— 			
Treasury Stock Reissued		— 			(886)		(a)	
Balance, December 31, 2018		513,450,036 			20,204,160 			
Issued		923,595 			— 			
	
Balance, December 31, 2019		514,373,631 			20,204,160 			
Issued		2,434,723 			— 			
	
Balance, December 31, 2020		516,808,354 			20,204,160 			

(a)    Reissued Treasury Stock used to fulfill share commitments related to AEP’s Share-based Compensation. See “Shared-based Compensation Plans” section of Note 15 for additional information.

At-the-Market (ATM) Program

In November 2020, AEP filed a prospectus supplement and executed an Equity Distribution Agreement (EDA), pursuant to which AEP may sell, from time to time, up to an aggregate of $1 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2% of the gross offering proceeds of the shares. There were no issuances under the ATM program for the year ended December 31, 2020.

Reverse Stock Split (Applies to SWEPCo)

In August 2020, SWEPCo executed a reverse stock split with each 2,048 shares of common stock issued and outstanding being combined into one share of common stock. The common stock of SWEPCo is wholly-owned by Parent.
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Long-term Debt

The following table details long-term debt outstanding:

				Weighted-Average		Interest Rate Ranges as of		Outstanding as of	
				Interest Rate as of		December 31,		December 31,	
Company		Maturity		December 31, 2020		2020		2019		2020		2019	
AEP										(in millions)	
Senior Unsecured Notes		2020-2050		3.97%		0.70%-8.13%		2.15%-8.13%		$	25,116.1 			$	21,180.7 		
Pollution Control Bonds (a)		2020-2036 (b)		2.39%		0.18%-4.63%		1.35%-5.38%		1,936.7 			1,998.8 		
Notes Payable – Nonaffiliated (c)		2020-2032		2.34%		0.84%-6.37%		2.42%-6.37%		239.1 			234.3 		
Securitization Bonds		2020-2029 (d)		2.78%		2.01%-3.77%		1.98%-5.31%		716.4 			1,025.1 		
Spent Nuclear Fuel Obligation (e)										281.2 			279.8 		
Junior Subordinated Notes (f)		2022-2023		2.32%		1.30%-3.40%		3.40%		1,624.1 			787.8 		
Other Long-term Debt		2020-2059		1.59%		0.81%-13.72%		1.15%-13.718%		1,158.9 			1,219.0 		
Total Long-term Debt Outstanding										$	31,072.5 			$	26,725.5 		
													
AEP Texas													
Senior Unsecured Notes		2022-2050		3.70%		2.10%-6.76%		2.40%-6.76%		$	3,687.6 			$	3,090.9 		
Pollution Control Bonds		2020-2030 (b)		3.42%		0.90%-4.55%		1.75%-4.55%		439.7 			490.3 		
	
Securitization Bonds		2020-2029 (d)		2.55%		2.06%-2.84%		1.98%-5.31%		492.6 			776.8 		
Other Long-term Debt		2022-2059		1.41%		1.40%-4.50%		3.05%-4.50%		200.5 			200.4 		
Total Long-term Debt Outstanding										$	4,820.4 			$	4,558.4 		
													
AEPTCo													
Senior Unsecured Notes		2021-2050		3.83%		3.10%-5.52%		3.10%-5.52%		$	3,948.5 			$	3,427.3 		

	
Total Long-term Debt Outstanding										$	3,948.5 			$	3,427.3 		
													
APCo													
Senior Unsecured Notes		2021-2050		4.94%		3.30%-7.00%		3.30%-7.00%		$	3,937.2 			$	3,442.7 		
Pollution Control Bonds (a)		2020-2036 (b)		1.77%		0.19%-4.63%		1.67%-5.38%		546.3 			546.1 		
	
Securitization Bonds		2023-2028 (d)		3.29%		2.01%-3.77%		2.008%-3.772%		223.8 			248.3 		
Other Long-term Debt		2022-2026		1.51%		1.32%-13.72%		2.97%-13.718%		126.8 			126.7 		
Total Long-term Debt Outstanding										$	4,834.1 			$	4,363.8 		
													
I&M													
Senior Unsecured Notes		2023-2048		4.38%		3.20%-6.05%		3.20%-6.05%		$	2,152.2 			$	2,150.7 		
Pollution Control Bonds (a)		2021-2025 (b)		2.21%		0.18%-3.05%		1.79%-3.05%		240.5 			240.0 		
Notes Payable – Nonaffiliated (c)		2020-2025		1.06%		0.84%-1.29%		2.42%-2.80%		146.7 			168.7 		
	
Spent Nuclear Fuel Obligation (e)										281.2 			279.8 		
Other Long-term Debt		2021-2025		1.49%		1.28%-6.00%		2.93%-6.00%		209.3 			211.0 		
Total Long-term Debt Outstanding										$	3,029.9 			$	3,050.2 		
													
OPCo													
Senior Unsecured Notes		2021-2049		4.82%		2.60%-6.60%		4.00%-6.60%		$	2,429.4 			$	2,081.0 		

	
Other Long-term Debt		2028		1.15%		1.15%		1.15%		0.8 			1.0 		
Total Long-term Debt Outstanding										$	2,430.2 			$	2,082.0 		
													
PSO													
Senior Unsecured Notes		2021-2049		4.55%		3.05%-6.63%		3.05%-6.625%		$	1,246.3 			$	1,245.6 		
Pollution Control Bonds		2020						4.45%		— 			12.7 		

Other Long-term Debt		2022-2027		1.47%		1.42%-3.00%		3.00%-3.20%		127.5 			127.9 		
Total Long-term Debt Outstanding										$	1,373.8 			$	1,386.2 		
													
SWEPCo													
Senior Unsecured Notes		2022-2048		4.04%		2.75%-6.20%		2.75%-6.20%		$	2,430.8 			$	2,428.9 		
	
Notes Payable – Nonaffiliated (c)		2024-2032		5.30%		4.58%-6.37%		4.58%-6.37%		62.4 			65.6 		
	
Other Long-term Debt		2021-2035		2.99%		2.25%-4.68%		3.08%-4.68%		143.2 			161.1 		
Total Long-term Debt Outstanding										$	2,636.4 			$	2,655.6 		

(a)For certain series of Pollution Control Bonds, interest rates are subject to periodic adjustment.  Certain series may be purchased on demand at periodic interest adjustment dates.  Letters of credit from banks and insurance policies support certain series. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets.
(b)Certain Pollution Control Bonds are subject to redemption earlier than the maturity date.
(c)Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.
(d)Dates represent the scheduled final payment dates for the securitization bonds. The legal maturity date is one to two years later. These bonds have been classified for maturity and repayment purposes based on the scheduled final payment date.
(e)Spent Nuclear Fuel Obligation consists of a liability along with accrued interest for disposal of SNF. See “Spent Nuclear Fuel Disposal” section of Note 6 for additional information.
(f)See “Equity Units” section below for additional information.
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As of December 31, 2020, outstanding long-term debt was payable as follows:

		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
2021		$	2,086.1 			$	88.7 			$	50.0 			$	518.3 			$	369.6 			$	500.1 			$	0.5 			$	106.2 		
2022		3,538.4 		(a)	716.0 			104.0 			355.4 			45.1 			0.1 			375.5 			281.2 		
2023		2,659.3 		(b)	278.5 			60.0 			26.6 			273.9 			0.1 			0.5 			6.2 		
2024		723.4 			96.0 			95.0 			113.5 			8.1 			0.1 			0.6 			31.2 		
2025		1,726.3 			324.5 			90.0 			443.9 			151.5 			0.1 			125.6 			6.2 		
After 2025		20,599.2 			3,357.0 			3,591.0 			3,418.3 			2,206.2 			1,950.3 			875.8 			2,225.5 		
Principal Amount		31,332.7 			4,860.7 			3,990.0 			4,876.0 			3,054.4 			2,450.8 			1,378.5 			2,656.5 		
Unamortized Discount, Net and Debt Issuance Costs		(260.2)			(40.3)			(41.5)			(41.9)			(24.5)			(20.6)			(4.7)			(20.1)		
Total Long-term Debt Outstanding		$	31,072.5 			$	4,820.4 			$	3,948.5 			$	4,834.1 			$	3,029.9 			$	2,430.2 			$	1,373.8 			$	2,636.4 		

(a)    Amount includes $805 million of Junior Subordinated Notes. See “Equity Units” section below for additional information.
(b)    Amount includes $850 million of Junior Subordinated Notes. See “Equity Units” section below for additional information.

Long-term Debt Subsequent Events

In January and February 2021, I&M retired $8 million and $7 million, respectively, of Notes Payable related to DCC Fuel.

In January 2021, OPCo issued $450 million of Senior Unsecured Notes.

In January 2021, PSO issued $400 million of variable rate Other Long-term Debt due in 2022, which it used to retire $250 million of Senior Unsecured Notes in February 2021.

In January and February 2021, Transource Energy issued $5 million and $9 million, respectively, of variable rate Other Long-term Debt due in 2023.

In February 2021, AEP Texas retired $11 million of Securitization Bonds.

In February 2021, APCo retired $12 million of Securitization Bonds.

Equity Units (Applies to AEP)

2020 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. The proceeds were used to support AEP’s overall capital expenditure plans.

Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 1.30% Junior Subordinated Notes (notes) due in 2025 and a forward equity purchase contract which settles after three years in 2023. The notes are expected to be remarketed in 2023, at which time the interest rate will reset at the then-current market rate. Investors may choose to remarket their notes to receive the remarketing proceeds and use those funds to settle the forward equity purchase contract, or accept the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the right to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 1.30% and a quarterly forward equity purchase contract payment of 4.825%.

368

Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance with the conversion ratios set forth below (subject to an anti-dilution adjustment):

•If the AEP common stock market price is equal to or greater than $99.95: 0.5003 shares per contract.
•If the AEP common stock market price is less than $99.95 but greater than $83.29: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
•If the AEP common stock market price is less than or equal to $83.29: 0.6003 shares per contract.

A holder’s ownership interest in the notes is pledged to AEP to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the forward equity purchase contract must be secured by a U.S. Treasury security which must be equal to the aggregate principal amount of the notes.

At the time of issuance, the $850 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $121 million were recorded in Deferred Credits and Other Noncurrent Liabilities with a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2023. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per-share dilution resulting from the equity unit issuance will be determined under the treasury stock method. The maximum amount of shares AEP will be required to issue to settle the purchase contract is 10,205,100 shares (subject to an anti-dilution adjustment).

2019 Equity Units

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. The proceeds were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC.

Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes (notes) due in 2024 and a forward equity purchase contract which settles after three years in 2022. The notes are expected to be remarketed in 2022, at which time the interest rate will reset at the then-current market rate. Investors may choose to remarket their notes to receive the remarketing proceeds and use those funds to settle the forward equity purchase contract, or accept the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the right to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 3.40% and a quarterly forward equity purchase contract payment of 2.725%.

Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance with the conversion ratios set forth below (subject to an anti-dilution adjustment):

•If the AEP common stock market price is equal to or greater than $99.58: 0.5021 shares per contract.
•If the AEP common stock market price is less than $99.58 but greater than $82.98: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
•If the AEP common stock market price is less than or equal to $82.98: 0.6026 shares per contract.

A holder’s ownership interest in the notes is pledged to AEP to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the forward equity purchase contract must be secured by a U.S. Treasury security which must be equal to the aggregate principal amount of the notes.
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At the time of issuance, the $805 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $62 million were recorded in Deferred Credits and Other Noncurrent Liabilities with a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2022. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per-share dilution resulting from the equity unit issuance will be determined under the treasury stock method. The maximum amount of shares AEP will be required to issue to settle the purchase contract is 9,701,860 shares (subject to an anti-dilution adjustment).

Debt Covenants (Applies to AEP and AEPTCo)

Covenants in AEPTCo’s note purchase agreements and indenture limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. AEPTCo’s contractually-defined priority debt was 1.6% of consolidated tangible net assets as of December 31, 2020. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreement.

Dividend Restrictions

Utility Subsidiaries’ Restrictions

Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. 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.

All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. The Federal Power Act also creates a reserve on retained earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M.

Certain AEP subsidiaries have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.

The most restrictive dividend limitation for certain AEP subsidiaries is through the Federal Power Act restriction, while for other AEP subsidiaries the most restrictive dividend limitation is through the credit agreements. As of December 31, 2020, the maximum amount of restricted net assets of AEP’s subsidiaries that may not be distributed to the Parent in the form of a loan, advance or dividend was $14 billion.

The Federal Power Act restriction limits the ability of the AEP subsidiaries owning hydroelectric generation to pay dividends out of retained earnings. Additionally, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2020, the amount of any such restrictions were as follows:

		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Restricted Retained Earnings		$	2,369.5 		(a)	$	694.0 			$	— 			$	175.1 			$	519.7 			$	— 			$	182.3 			$	571.9 		

(a)    Includes the restrictions of consolidated and non-consolidated subsidiaries.
370

Parent Restrictions (Applies to AEP)

The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends.  Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.

Pursuant to the leverage restrictions in credit agreements, AEP must 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 the credit agreements.  As of December 31, 2020, AEP had $7.1 billion of available retained earnings to pay dividends to common shareholders. AEP paid $1.4 billion, $1.3 billion and $1.3 billion of dividends to common shareholders for the years ended December 31, 2020, 2019 and 2018, respectively.

Lines of Credit and Short-term Debt (Applies to AEP and SWEPCo)

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.  As of December 31, 2020, AEP had a $4 billion revolving credit facility to support its commercial paper program.  The commercial paper program for the year ended 2020, had a weighted-average interest rate of 1.28% and a maximum amount outstanding of $3 billion.  AEP’s outstanding short-term debt was as follows:

				December 31,	
				2020		2019	
Company		Type of Debt		Outstanding
Amount		Interest
Rate (a)		Outstanding
Amount		Interest
Rate (a)	
				(in millions)				(in millions)			
AEP		Securitized Debt for Receivables (b)		$	592.0 			0.85 	%		$	710.0 			2.42 	%	
AEP		Commercial Paper		1,852.3 			0.29 	%		2,110.0 			2.10 	%	

SWEPCo		Notes Payable		35.0 			2.55 	%		18.3 			3.29 	%	
		Total Short-term Debt		$	2,479.3 					$	2,838.3 				

(a)    Weighted-average rate.
(b)    Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

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Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries)

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP.  The AEP System Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC.  The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2020 and 2019 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets.  The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits are described in the following tables:

Year Ended December 31, 2020:

		Maximum				Average				Net Loans to				
		Borrowings		Maximum		Borrowings		Average		(Borrowings from)		Authorized		
		from the		Loans to the		from the		Loans to the		the Utility Money		Short-term		
		Utility		Utility		Utility		Utility		Pool as of		Borrowing		
Company		Money Pool		Money Pool		Money Pool		Money Pool		December 31, 2020		Limit		
		(in millions)		
AEP Texas		$	320.4 			$	313.4 			$	132.0 			$	139.0 			$	(67.1)			$	500.0 			
AEPTCo		358.4 			259.7 			116.3 			55.0 			(155.4)			820.0 		(a)	
APCo		434.3 			189.0 			242.8 			76.3 			2.8 			500.0 			
I&M		218.6 			13.4 			114.5 			13.3 			(89.7)			500.0 			
OPCo		353.9 			32.8 			182.4 			25.2 			(259.2)			500.0 			
PSO		155.4 			57.1 			72.3 			28.4 			(155.4)			300.0 			
SWEPCo		178.9 			— 			113.0 			— 			(124.6)			350.0 			

Year Ended December 31, 2019:

		Maximum				Average				Net Loans to				
		Borrowings		Maximum		Borrowings		Average		(Borrowings from)		Authorized		
		from the		Loans to the		from the		Loans to the		the Utility Money		Short-term		
		Utility		Utility		Utility		Utility		Pool as of		Borrowing		
Company		Money Pool		Money Pool		Money Pool		Money Pool		December 31, 2019		Limit		
		(in millions)		
AEP Texas		$	390.7 			$	213.1 			$	239.3 			$	194.4 			$	199.7 			$	500.0 			
AEPTCo		374.9 			244.4 			152.0 			52.8 			(119.0)			795.0 		(a)	
APCo		270.0 			232.2 			115.9 			51.9 			(214.6)			500.0 			
I&M		158.8 			66.0 			71.5 			16.2 			(101.2)			500.0 			
OPCo		291.2 			178.6 			129.2 			50.1 			(131.0)			500.0 			
PSO		140.5 			215.6 			63.9 			98.3 			38.8 			300.0 			
SWEPCo		105.1 			81.4 			53.3 			13.6 			(59.9)			350.0 			

(a)    Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.

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The activity in the above tables does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2020 and 2019 are included in Advances to Affiliates on each subsidiaries’ balance sheets. The Nonutility Money Pool participants’ money pool activity is described in the following tables:

Year Ended December 31, 2020:

		Maximum Loans		Average Loans		Loans to the Nonutility	
		to the Nonutility		to the Nonutility		Money Pool as of	
Company		Money Pool		Money Pool		December 31, 2020	
		(in millions)	
AEP Texas		$	7.5 			$	7.1 			$	7.1 		
SWEPCo		2.1 			2.1 			2.1 		

Year Ended December 31, 2019:

		Maximum Loans		Average Loans		Loans to the Nonutility	
		to the Nonutility		to the Nonutility		Money Pool as of	
Company		Money Pool		Money Pool		December 31, 2019	
		(in millions)	
AEP Texas		$	8.0 			$	7.7 			$	7.5 		
SWEPCo		2.1 			2.0 			2.1 		

AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to and borrowings from AEP as of December 31, 2020 and 2019 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct financing activities with AEP and corresponding authorized borrowing limits are described in the following tables:

Year Ended December 31, 2020:

Maximum		Maximum		Average		Average		Borrowings from		Loans to		Authorized		
Borrowings		Loans		Borrowings		Loans		AEP as of		AEP as of		Short-term		
from AEP		to AEP		from AEP		to AEP		December 31, 2020		December 31, 2020		Borrowing Limit		
(in millions)		
$	1.4 			$	215.3 			$	1.3 			$	132.6 			$	1.2 			$	109.0 			$	50.0 		(a)	

Year Ended December 31, 2019:

Maximum		Maximum		Average		Average		Borrowings from		Loans to		Authorized		
Borrowings		Loans		Borrowings		Loans		AEP as of		AEP as of		Short-term		
from AEP		to AEP		from AEP		to AEP		December 31, 2019		December 31, 2019		Borrowing Limit		
(in millions)		
$	1.3 			$	153.5 			$	1.3 			$	68.0 			$	1.3 			$	68.7 			$	75.0 		(a)	

(a)    Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:

	Years Ended December 31,	
	2020		2019		2018	
Maximum Interest Rate	2.70 	%		3.43 	%		2.97 	%	
Minimum Interest Rate	0.27 	%		1.77 	%		1.81 	%	

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The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized in the following table:

		Average Interest Rate for Funds Borrowed
from the Utility Money Pool for the
Years Ended December 31,		Average Interest Rate for Funds Loaned
to the Utility Money Pool for the
Years Ended December 31,	
Company		2020		2019		2018		2020		2019		2018	
AEP Texas		1.51 	%		2.63 	%		2.26 	%		0.81 	%		2.03 	%		2.29 	%	
AEPTCo		1.29 	%		2.64 	%		2.27 	%		1.99 	%		2.41 	%		2.10 	%	
APCo		2.12 	%		2.45 	%		2.26 	%		0.85 	%		2.66 	%		2.21 	%	
I&M		1.07 	%		2.34 	%		2.16 	%		1.18 	%		2.60 	%		2.08 	%	
OPCo		0.99 	%		2.67 	%		2.18 	%		2.06 	%		2.68 	%		2.47 	%	
PSO		0.92 	%		2.85 	%		2.27 	%		1.95 	%		2.27 	%		1.98 	%	
SWEPCo		1.27 	%		2.72 	%		2.31 	%		— 	%		2.22 	%		2.00 	%	

Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:

			 	Maximum Interest Rate	 	Minimum Interest Rate	 	Average Interest Rate	
Year Ended			 	for Funds Loaned to	 	for Funds Loaned to	 	for Funds Loaned to	
December 31,		Company	 	the Nonutility Money Pool	 	the Nonutility Money Pool	 	the Nonutility Money Pool	
2020		AEP Texas	 	2.70 	%		0.27 	%		1.18 	%	
2020		SWEPCo	 	2.70 	%		0.27 	%		1.18 	%	
									
2019		AEP Texas		3.02 	%		1.91 	%		2.56 	%	
2019		SWEPCo		3.02 	%		1.91 	%		2.55 	%	
									
2018		AEP Texas		2.97 	%		1.83 	%		2.36 	%	
2018		SWEPCo		2.97 	%		1.83 	%		2.36 	%	

AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:

 	 	Maximum	 	Minimum	 	Maximum	 	Minimum	 	Average	 	Average	
 	 	Interest Rate	 	Interest Rate	 	Interest Rate	 	Interest Rate	 	Interest Rate	 	Interest Rate	
 	 	for Funds	 	for Funds	 	for Funds	 	for Funds	 	for Funds	 	for Funds	
Year Ended	 	Borrowed from	 	Borrowed from	 	Loaned to	 	Loaned to	 	Borrowed from	 	Loaned to	
December 31,	 	AEP	 	AEP		AEP	 	AEP	 	AEP	 	AEP	
2020	 	2.70 	%		0.27 	%		2.70 	%		0.27 	%		1.20 	%		1.13 	%	
2019	 	3.02 	%		1.91 	%		3.02 	%		1.91 	%		2.55 	%		2.51 	%	
2018		2.97 	%		1.76 	%		2.97 	%		1.76 	%		2.36 	%		2.36 	%	

Interest expense and interest income related to the Utility Money Pool, Nonutility Money Pool and direct borrowing financing relationship are included in Interest Expense and Interest Income, respectively, on each of the Registrant Subsidiaries’ statements of income.  The interest expense and interest income related to the corporate borrowing programs were immaterial for the years ended December 31, 2020, 2019 and 2018.

Credit Facilities

See “Letters of Credit” section of Note 6 for additional information.

374

Securitized Accounts Receivables – AEP Credit (Applies to AEP)

AEP Credit has a receivables securitization agreement that provides a commitment of $750 million from bank conduits to purchase receivables and expires in September 2022. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries.  These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.

In May 2020, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As of December 31, 2020, 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. The receivables that are ineligible under the receivables securitization agreement are financed with short-term debt at AEP Credit.

Accounts receivable information for AEP Credit was as follows:

	Years Ended December 31,	
	2020		2019		2018	
	(dollars in millions)	
Effective Interest Rates on Securitization of Accounts Receivable	0.85 	%		2.42 	%		2.16 	%	
Net Uncollectible Accounts Receivable Written Off	$	15.3 			$	26.6 			$	27.6 		

	December 31,	
	2020		2019	
	(in millions)	
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts	$	958.4 			$	841.8 		
Short-term – Securitized Debt of Receivables	592.0 			710.0 		
Delinquent Securitized Accounts Receivable	62.3 			39.6 		
Bad Debt Reserves Related to Securitization	60.0 			32.1 		
Unbilled Receivables Related to Securitization	296.8 			266.8 		

AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.

Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEP Texas and AEPTCo)

Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables.  APCo does not have regulatory authority to sell its West Virginia accounts receivable.  The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income.  The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.

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The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement were:

		December 31,	
Company		2020		2019	
		(in millions)	
APCo		$	136.0 			$	120.9 		
I&M		170.5 			141.8 		
OPCo		398.8 			330.3 		
PSO		85.0 			101.1 		
SWEPCo		158.6 			125.2 		

The fees paid to AEP Credit for customer accounts receivable sold were:

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
APCo		$	5.2 			$	7.4 			$	7.0 		
I&M		7.9 			11.1 			9.2 		
OPCo		24.1 			27.1 			26.3 		
PSO		4.8 			7.8 			7.9 		
SWEPCo		6.7 			10.2 			8.9 		

The proceeds on the sale of receivables to AEP Credit were:

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
APCo		$	1,272.9 			$	1,310.3 			$	1,421.0 		
I&M		1,891.8 			1,824.2 			1,843.0 		
OPCo		2,366.2 			2,293.6 			2,674.5 		
PSO		1,221.0 			1,442.5 			1,484.6 		
SWEPCo		1,593.8 			1,618.5 			1,736.1 		
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15.  STOCK-BASED COMPENSATION

The disclosures in this note apply to AEP only. The impact of AEP’s share-based compensation plans is insignificant to the financial statements of the Registrant Subsidiaries.

Awards under AEP’s long-term incentive plan may be granted to employees and directors. The Amended and Restated American Electric Power System Long-Term Incentive Plan (Prior Plan), was replaced prospectively for new grants by the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP) effective in April 2015. The 2015 LTIP was subsequently amended in September 2016. The 2015 LTIP provides for a maximum of 10 million AEP common shares to be available for grant to eligible employees and directors. As of December 31, 2020, 6,712,148 shares remained available for issuance under the 2015 LTIP. No new awards may be granted under the Prior Plan. The 2015 LTIP awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. Shares issued pursuant to a stock option or a stock appreciation right reduce the shares remaining available for grants under the 2015 LTIP by 0.286 of a share. Each share issued for any other award that settles in AEP stock reduces the shares remaining available for grants under the 2015 LTIP by one share. Cash settled awards do not reduce the number of shares remaining available under the 2015 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted under these plans.

Performance Shares

Performance units granted prior to 2017 were settled in cash rather than AEP common stock and did not reduce the number of shares remaining available under the 2015 LTIP. Those performance units had a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period. Performance shares granted in and after 2017 are settled in AEP common stock and reduce the aggregate share authorization. In all cases the number of performance shares held at the end of the three-year performance period is multiplied by the performance score for such period to determine the actual number of performance shares that participants realize. The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the Human Resources Committee of AEP’s Board of Directors (HR Committee).

Certain employees must satisfy a minimum stock ownership requirement. If those employees have not met their stock ownership requirement, a portion or all of their performance shares are mandatorily deferred as AEP career shares to the extent needed to meet their stock ownership requirement.  AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to a share of AEP common stock.  AEP career shares are settled in AEP common stock after the participant’s termination of employment.

AEP career shares are recorded in Paid-in Capital on the balance sheets. Amounts equivalent to cash dividends on both performance shares and AEP career shares accrue as additional shares.  Management records compensation cost for performance shares over an approximately three-year vesting period. Performance shares are recorded as mezzanine equity on the balance sheets until the vesting date and compensation cost is calculated at fair value based on metrics for each grant. Performance shares granted in 2020 had three performance metrics: (a) three-year cumulative operating earnings per-share with a 50% weight, (b) total shareholder return with a 40% weight and (c) non-emitting generation capacity as a percentage of total owned and purchased capacity with a 10% weight. Performance shares granted prior to 2020 had two equally-weighted performance metrics: (a) three-year cumulative operating earnings per-share and (b) total shareholder return. The three-year cumulative operating earnings per-share metric and non-emitting generating capacity metric are adjusted quarterly for changes in performance relative to a target approved by the HR Committee. The total shareholder return metric is measured relative to a peer group of similar companies and is based on a third-party Monte Carlo valuation. The value related to this metric does not change over the three-year vesting period.

377

The HR Committee awarded performance shares and reinvested dividends on outstanding performance shares and AEP career shares as follows:

		Years Ended December 31,	
Performance Shares		2020		2019		2018	
Awarded Shares (in thousands)		424.8 			535.0 			581.4 		
Weighted-Average Share Fair Value at Grant Date		$	116.56 			$	83.21 			$	67.21 		
Vesting Period (in years)		3		3		3	

Performance Shares and AEP Career Shares
(Reinvested Dividends Portion)		Years Ended December 31,	
		2020		2019		2018	
Awarded Shares (in thousands) (a)		73.4 			66.4 			80.2 		
Weighted-Average Fair Value at Grant Date		$	84.87 			$	88.73 			$	70.58 		
Vesting Period (in years)		(b)		(b)		(b)	

(a)All awarded dividends in both 2020 and 2019 were equity awards and awarded dividends in 2018 were a mix of equity awards and liability awards.
(b)The vesting period for the reinvested dividends on performance shares is equal to the remaining life of the related performance shares.  Dividends on AEP career shares vest immediately when the dividend is awarded but are not settled in AEP common stock until after the participant’s AEP employment ends.

Performance scores and final awards are determined and approved by the HR Committee in accordance with the pre-established performance measures within approximately two months after the end of the performance period.

The certified performance scores and shares earned for the three-year periods were as follows:

		Years Ended December 31,	
Performance Shares		2020		2019		2018	
Certified Performance Score		128.2 	%		132.7 	%		136.7 	%	
Performance Shares Earned		757,858 			792,897 			820,780 		
Performance Shares Mandatorily Deferred as AEP Career Shares		13,614 			10,063 			11,248 		
Performance Shares Voluntarily Deferred into the Incentive Compensation Deferral Program		26,936 			49,392 			56,826 		
Performance Shares to be Settled (a)		717,308 			733,442 			752,706 		

(a)Performance shares settled for the three-year periods ended December 31, 2020 and 2019 settled in AEP common stock. Performance units settled for the three-year period ended December 31, 2018 settled in cash. In all cases, the settlement of common stock or cash occurs in the quarter following the end of the year shown.

The settlements were as follows:

		Years Ended December 31,	
Performance Shares and AEP Career Shares		2020		2019		2018	
		(in millions)	
Cash Settlements for Performance Units		$	— 			$	58.3 			$	66.9 		
AEP Common Stock Settlements for Performance Shares		75.4 			— 			— 		
AEP Common Stock Settlements for Career Share Distributions		1.9 			6.6 			5.1 		

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A summary of the status of AEP’s nonvested Performance Shares as of December 31, 2020 and changes during the year ended December 31, 2020 were as follows:

Nonvested Performance Shares		Shares		Weighted
Average
Grant Date
Fair Value	
		(in thousands)			
Nonvested as of January 1, 2020		1,113.4 			$	73.64 		
Awarded		424.8 			116.56 		
Dividends		53.8 			84.91 		
Vested (a)		(597.0)			66.45 		
Forfeited		(56.4)			87.58 		
Nonvested as of December 31, 2020		938.6 			98.05 		

(a)The vested Performance Shares will be converted to 717 thousand shares based on the closing share price on the day before settlement.

Monte Carlo Valuation

AEP engages a third-party for a Monte Carlo valuation to calculate the fair value of the total shareholder return metric for the performance shares awarded during and after 2017. The valuations use a lattice model and the expected volatility assumptions used were the historical volatilities for AEP and the members of their peer group. The assumptions used in the Monte Carlo valuations were as follows:

		Years Ended December 31,	
Assumptions		2020		2019		2018	
Valuation Period (in years) (a)		2.87		2.87		2.87	
Expected Volatility Minimum		13.67 	%		14.83 	%		14.77 	%	
Expected Volatility Maximum		28.15 	%		25.57 	%		26.72 	%	
Expected Volatility Average		16.39 	%		17.39 	%		17.90 	%	
Dividend Rate (b)		— 	%		— 	%		— 	%	
Risk Free Rate		1.40 	%		2.49 	%		2.34 	%	

(a)Period from award date to vesting date.
(b)Equivalent to reinvesting dividends.

Restricted Stock Units

The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments.  The RSUs accrue dividends as additional RSUs. The additional RSUs granted as dividends vest on the same date as the underlying RSUs. RSUs are converted into shares of AEP common stock upon vesting, except the RSUs granted prior to 2017 to AEP’s executive officers which settled in cash. Executive officers are those officers who are subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934. For RSUs that settle in shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period.  Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price.  For RSUs that settled in cash, compensation cost was recorded over the vesting period and adjusted for changes in fair value until vested.  The fair value at vesting was determined by multiplying the number of RSUs vested by the 20-day average closing price of AEP common stock.  The maximum contractual term of outstanding RSUs is approximately 40 months from the grant date.

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The HR Committee awarded RSUs, including additional units awarded as dividends, as follows:

		Years Ended December 31,	
Restricted Stock Units		2020		2019		2018	
Awarded Units (in thousands)		268.7 			304.8 			260.0 		
Weighted-Average Grant Date Fair Value		$	94.38 			$	81.57 			$	67.96 		

The total fair value and total intrinsic value of restricted stock units vested were as follows:

		Years Ended December 31,	
Restricted Stock Units		2020		2019		2018	
		(in millions)	
Fair Value of Restricted Stock Units Vested		$	22.9 			$	16.3 			$	16.6 		
Intrinsic Value of Restricted Stock Units Vested (a)		25.2 			21.6 			19.2 		

(a)Intrinsic value is calculated as market price at the vesting date.

A summary of the status of AEP’s nonvested RSUs as of December 31, 2020 and changes during the year ended December 31, 2020 were as follows:

Nonvested Restricted Stock Units		Shares/Units		Weighted
Average
Grant Date
Fair Value	
		(in thousands)			
Nonvested as of January 1, 2020		516.9 			$	75.55 		
Awarded		268.7 			94.38 		
Vested		(307.6)			74.58 		
Forfeited		(30.0)			84.27 		
Nonvested as of December 31, 2020		448.0 			86.56 		

The total aggregate intrinsic value of nonvested RSUs as of December 31, 2020 was $37 million and the weighted-average remaining contractual life was 1.6 years.

Retirement Incentive and Severance Awards

In 2020 64,186 shares with a weighted-average grant date fair value of $83.74 were granted in connection with the voluntary retirement incentive program and other executive severance. The shares were fully vested on the grant date with a fair value of $5 million. See “Voluntary Retirement Incentive Program” section of Note 1 for additional information.

Other Stock-Based Plans

AEP also has a Stock Unit Accumulation Plan for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of the compensation for their services as a director.  The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned.  Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units.  The stock units granted to non-employee directors are fully vested on their grant date.  Stock units are settled in cash upon termination of board service or up to 10 years later if the participant so elects.  Cash settlements for stock units are calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date. After five years of service on the Board of Directors, non-employee directors receive subsequent AEP stock units as contributions to an AEP stock fund awarded under the Stock Unit Accumulation Plan. Such amounts may be exchanged into other market-based investments that are similar to the investment options available to employees that participate in AEP’s Incentive Compensation Deferral Plan. These balances are also paid in cash upon termination of board service or up to 10 years later if the participant so elects.
380

Management records compensation cost for stock units when the units are awarded and adjusts the liability for changes in value based on the current 20-day average closing price of AEP common stock on the valuation date.

For the years ended December 31, 2020, 2019 and 2018, cash settlements for stock unit distributions were immaterial.

The Board of Directors awarded stock units, including units awarded for dividends, as follows:

		Years Ended December 31,	
Stock Unit Accumulation Plan for Non-Employee Directors		2020		2019		2018	
Awarded Units (in thousands)		12.1 			10.0 			11.4 		
Weighted-Average Grant Date Fair Value		$	83.80 			$	89.13 			$	70.41 		

Share-based Compensation Plans

For share-based payment arrangements the compensation cost, the actual tax benefit from the tax deductions for compensation cost recognized in income and the total compensation cost capitalized were as follows:

		Years Ended December 31,	
Share-based Compensation Plans		2020		2019		2018	
		(in millions)	
Compensation Cost for Share-based Payment Arrangements (a)		$	53.8 			$	57.9 			$	53.2 		
Actual Tax Benefit		7.2 			8.4 			7.7 		
Total Compensation Cost Capitalized		20.4 			20.0 			19.7 		

(a)Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.

As of December 31, 2020, there was $78 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the 2015 LTIP. Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance shares is adjusted each period and as forfeitures for all award types are realized.  AEP’s unrecognized compensation cost will be recognized over a weighted-average period of 1.39 years.

Under the 2015 LTIP, AEP is permitted to use authorized but unissued shares, treasury shares, shares acquired in the open market specifically for distribution under these plans, or any combination thereof to fulfill share commitments. AEP’s current practice is to use authorized but unissued shares to fulfill share commitments. The number of shares used to fulfill share commitments is generally reduced to offset tax withholding obligations.
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16.  RELATED PARTY TRANSACTIONS

The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise.

For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Corporate Borrowing Program – AEP System” and “Securitized Accounts Receivables – AEP Credit” sections of Note 14.

Power Coordination Agreement (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo)

Effective January 1, 2014, the FERC approved the PCA. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. The PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective Off-system Sales and purchase activities.

AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Certain power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. With the transfer of OPCo’s generation assets to AGR in 2014, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf.

System Integration Agreement (Applies to APCo, I&M, PSO and SWEPCo)

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo.  Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies.

382

Affiliated Revenues and Purchases

The tables below represent revenues from affiliates, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries:

Related Party Revenues		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Year Ended December 31, 2020															
Direct Sales to East Affiliates		$	— 			$	— 			$	112.5 			$	— 			$	— 			$	— 			$	— 		
	
Auction Sales to OPCo (a)		— 			— 			5.3 			3.1 			— 			— 			— 		
Direct Sales to AEPEP		87.5 			— 			— 			— 			— 			— 			— 		
Transmission Revenues		— 			885.0 			49.1 			2.9 			16.6 			— 			37.4 		
Other Revenues		3.3 			11.3 			7.8 			4.5 			24.9 			5.2 			1.6 		
Total Affiliated Revenues		$	90.8 			$	896.3 			$	174.7 			$	10.5 			$	41.5 			$	5.2 			$	39.0 		

Related Party Revenues		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Year Ended December 31, 2019															
Direct Sales to East Affiliates		$	— 			$	— 			$	128.6 			$	— 			$	— 			$	— 			$	— 		
	
Auction Sales to OPCo (a)		— 			— 			11.4 			6.7 			— 			— 			— 		
Direct Sales to AEPEP		157.2 			— 			— 			— 			— 			— 			(0.1)		
Transmission Revenues		— 			795.5 			58.5 			0.7 			7.7 			1.3 			3.6 		
Other Revenues		3.3 			11.2 			6.8 			3.1 			19.6 			4.8 			1.4 		
Total Affiliated Revenues		$	160.5 			$	806.7 			$	205.3 			$	10.5 			$	27.3 			$	6.1 			$	4.9 		

Related Party Revenues		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Year Ended December 31, 2018															
Direct Sales to East Affiliates		$	— 			$	— 			$	133.2 			$	0.1 			$	— 			$	— 			$	— 		
	
Auction Sales to OPCo (a)		— 			— 			5.8 			7.1 			— 			— 			— 		
Direct Sales to AEPEP		103.6 			— 			— 			— 			— 			— 			— 		
Transmission Revenues		— 			591.4 			36.4 			11.7 			3.9 			0.9 			26.9 		
Other Revenues		1.6 			7.5 			6.0 			3.2 			17.1 			4.5 			1.5 		
Total Affiliated Revenues		$	105.2 			$	598.9 			$	181.4 			$	22.1 			$	21.0 			$	5.4 			$	28.4 		

(a)Refer to the Ohio Auctions section below for further information regarding these amounts.

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The tables below represent the purchased power expenses incurred for purchases from affiliates. AEP Texas, AEPTCo, APCo, PSO and SWEPCo did not purchase any power from affiliates for the years ended December 31, 2020, 2019 and 2018.

Related Party Purchases		I&M		OPCo	
		(in millions)	
Year Ended December 31, 2020					
	
Auction Purchases from AEPEP (a)		$	— 			$	51.0 		
Auction Purchases from AEP Energy (a)		— 			58.7 		
Auction Purchases from AEPSC (a)		— 			10.0 		
Direct Purchases from AEGCo		172.8 			— 		
Total Affiliated Purchases		$	172.8 			$	119.7 		

															
Related Party Purchases		I&M		OPCo	
		(in millions)	
Year Ended December 31, 2019					
	
Auction Purchases from AEPEP (a)		$	— 			$	64.6 		
Auction Purchases from AEP Energy (a)		— 			69.9 		
Auction Purchases from AEPSC (a)		— 			21.5 		
Direct Purchases from AEGCo		214.9 			— 		
Total Affiliated Purchases		$	214.9 			$	156.0 		

															
Related Party Purchases		I&M		OPCo	
		(in millions)	
Year Ended December 31, 2018					
	
Auction Purchases from AEPEP (a)		$	— 			$	79.7 		
Auction Purchases from AEP Energy (a)		— 			41.0 		
Auction Purchases from AEPSC (a)		— 			14.6 		
Direct Purchases from AEGCo		237.9 			— 		
Total Affiliated Purchases		$	237.9 			$	135.3 		

(a)    Refer to the Ohio Auctions section below for further information regarding this amount.

The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income.  Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses.

PJM and SPP Transmission Service Charges (Applies to all Registrant Subsidiaries except AEP Texas)

The AEP East Companies are parties to the TA, which defines how transmission costs through the PJM OATT are allocated among the AEP East Companies on a 12-month average coincident peak basis. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to AEP East Companies through the PJM OATT.

The following table shows the net transmission service charges recorded by APCo, I&M and OPCo:

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
APCo		$	243.2 			$	222.3 			$	128.3 		
I&M		145.9 			143.5 			91.4 		
OPCo		417.4 			373.4 			210.1 		

The charges shown above are recorded in Other Operation expenses on the statements of income.
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PSO, SWEPCo and AEPSC are parties to the TCA in connection with the operation of the transmission assets of PSO and SWEPCo.  The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement.  This includes the performance of transmission planning studies, the interaction of such companies with independent system operators and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff.

Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf.  The allocations have been governed by the FERC-approved OATT for the SPP. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to PSO and SWEPCo through the SPP OATT.

The following table shows the net transmission service charges recorded by PSO and SWEPCo:

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
PSO		$	69.7 			$	46.9 			$	65.9 		
SWEPCo		31.3 			20.1 			10.5 		

The charges shown above are recorded in Other Operation expenses on the statements of income.

AEPTCo provides transmission services to affiliates in accordance with the OATT, TA and TCA. AEPTCo recorded affiliated transmission revenues in Sales to AEP Affiliates on the statements of income. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions.

ERCOT Transmission Service Charges (Applies to AEP and AEP Texas)

Pursuant to an order from the PUCT, ETT bills AEP Texas for its ERCOT wholesale transmission services. ETT billed AEP Texas $28 million, $27 million and $27 million for transmission services in 2020, 2019 and 2018, respectively. The billings are recorded in Other Operation expenses on AEP Texas’ statements of income.

Oklaunion PPA between AEP Texas and AEPEP (Applies to AEP Texas)

In 2007, AEP Texas entered into a PPA with an affiliate, AEPEP, whereby AEP Texas agreed to sell AEPEP 100% of AEP Texas’ capacity and associated energy from its undivided interest (54.69%) in the Oklaunion Power Station. The PPA was approved by the FERC. In September 2018, the co-owners of Oklaunion Power Station voted to close the plant in 2020. Effective October 2018, AEP Texas increased depreciation expense to ensure the plant balances are fully depreciated as of September 2020 and recovered through the PPA billings to AEPEP. Under the early termination provisions of the PPA, AEPEP paid AEP Texas the full Property, Plant and Equipment balance through depreciation payments until termination of the PPA due to the plant closing in September 2020. See “Dispositions” section of Note 7 for additional information.

AEP Texas recorded revenue of $88 million, $157 million and $104 million from AEPEP for the years ended December 31, 2020, 2019 and 2018, respectively. These amounts are included in Sales to AEP Affiliates on AEP Texas’ statements of income.

385

Joint License Agreement (Applies to AEPTCo, APCo, I&M, OPCo and PSO)

AEPTCo entered into a 50-year joint license agreement with APCo, I&M, KPCo, OPCo and PSO, respectively, allowing either party to occupy the granting party’s facilities or real property. In addition, AEPTCo entered into a 5-year joint license agreement with APCo and WPCo. After the expiration of these agreements, the term shall automatically renew for successive one-year terms unless either party provides notice. The joint license billing provides compensation to the granting party for the cost of carrying assets, including depreciation expense, property taxes, interest expense, return on equity and income taxes. AEPTCo recorded the following costs in Other Operation expense related to these agreements:

		Years Ended December 31,	
Billing Company		2020		2019		2018	
		(in millions)	
APCo		$	0.9 			$	0.2 			$	— 		
I&M		3.0 			1.5 			2.2 		
KPCo		0.4 			0.3 			0.2 		
OPCo		4.5 			2.2 			2.9 		
PSO		0.4 			0.3 			0.3 		
WPCo		0.2 			0.1 			— 		

APCo, I&M, KPCo, OPCo, PSO and WPCo recorded income related to these agreements in Sales to AEP Affiliates on the statements of income.

Ohio Auctions (Applies to APCo, I&M and OPCo)

In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEP Energy, AEPEP, APCo, KPCo, I&M and WPCo participate in the auction process and have been awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions.

Unit Power Agreements (Applies to I&M)

UPA between AEGCo and I&M

A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility.  Subsequently, I&M assigns 30% of the power to KPCo.  See the “UPA between AEGCo and KPCo” section below.  I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC.  In November 2020, management announced that AEP will not renew the Rockport Plant, Unit 2 lease when it expires in December 2022. The I&M Power Agreement will continue in effect until the debt obligations of AEGCo secured by the Rockport Plant have been satisfied and discharged (currently expected to be December 2028).

UPA between AEGCo and KPCo

Pursuant to an assignment between I&M and KPCo and a UPA between AEGCo and KPCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant.  KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement.  In November 2020, management announced that AEP will not renew the Rockport Plant, Unit 2 lease when it expires in December 2022. The KPCo UPA ends in December 2022.

386

Cook Coal Terminal (Applies to I&M, PSO and SWEPCo)

Cook Coal Terminal, which is owned by AEGCo, performs coal transloading and storage services at cost for I&M.  The coal transloading costs were $12 million, $13 million and $12 million in 2020, 2019 and 2018, respectively. I&M recorded the cost of transloading services in Fuel on the balance sheets.

Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo.  The railcar maintenance costs were as follows:

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
I&M		$	0.9 			$	1.3 			$	1.5 		
PSO		0.7 			0.8 			0.7 		
SWEPCo		3.0 			4.0 			3.4 		

I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets.

I&M Barging, Urea Transloading and Other Services (Applies to APCo and I&M)

I&M provides barging, urea transloading and other transportation services to affiliates.  Urea is a chemical used to control NOx emissions at certain generation plants in the AEP System.  I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income.  The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses.  The amounts of affiliated expenses were:

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
AEGCo		$	10.6 			$	14.9 			$	19.9 		
	
APCo		43.7 			38.9 			35.1 		
KPCo		3.2 			4.8 			4.2 		
WPCo		3.3 			4.8 			4.2 		

Central Machine Shop (Applies to APCo, I&M, PSO and SWEPCo)

APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System.  APCo defers the cost of performing these services on the balance sheet and then transfers the cost to the affiliate for reimbursement.  The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received.  These billings are recoverable from customers.  The following table provides the amounts billed by APCo to the following affiliates:

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
	
AGR		$	2.9 			$	0.8 			$	1.6 		
I&M		3.2 			2.3 			2.4 		
KPCo		0.9 			1.4 			1.7 		
PSO		0.9 			1.1 			0.5 		
SWEPCo		0.5 			1.1 			0.7 		

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Sales and Purchases of Property

Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property.  There were no gains or losses recorded on the transactions.  The following tables show the sales and purchases, recorded at net book value:

Sales

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
AEP Texas		$	0.9 			$	0.9 			$	0.3 		
AEPTCo		0.2 			— 			— 		
APCo		5.7 			5.5 			5.4 		
I&M		1.5 			7.5 			8.2 		
OPCo		7.0 			7.0 			10.7 		
PSO		1.1 			0.8 			1.0 		
SWEPCo		0.8 			0.2 			0.8 		

Purchases

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
AEP Texas		$	1.5 			$	0.3 			$	0.1 		
AEPTCo		6.0 			10.2 			18.5 		
APCo		1.3 			6.0 			0.6 		
I&M		3.4 			0.9 			2.0 		
OPCo		1.2 			3.0 			2.8 		
PSO		0.4 			0.5 			1.3 		
SWEPCo		2.8 			0.7 			0.8 		

The amounts above are recorded in Property, Plant and Equipment on the balance sheets.

Sempra Renewables LLC PPAs (Applies to I&M, OPCo and SWEPCo)

In April 2019, AEP acquired Sempra Renewables LLC and its ownership interests in 724 MWs of wind generation. The operating wind generation portfolio includes seven wind farms. Prior to the acquisition, two wind farms had existing PPAs with I&M, OPCo and SWEPCo. One of the joint venture wind farms has PPAs with I&M and OPCo for a portion of its energy production. The I&M portion totaled $11 million and $9 million and the OPCo portion totaled $23 million and $17 million, respectively, for the years ended December 31, 2020 and 2019. Another joint venture wind farm has a PPA with SWEPCo for a portion of its energy production which totaled $14 million and $10 million, respectively, of purchased electricity for the years ended December 31, 2020 and 2019. See “Acquisitions” section of Note 7 for additional information.

Intercompany Billings

The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical.  The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies.  The billings for services are made at cost and include no compensation for the use of equity capital.

388

Charitable Contributions to AEP Foundation

The American Electric Power Foundation is funded by American Electric Power and its utility operating units. The Foundation provides a permanent, ongoing resource for charitable initiatives and multi-year commitments in the communities served by AEP and initiatives outside of AEP’s 11-state service area. Charitable contributions to the AEP Foundation were recorded in Other Operation on the statements of income. In 2020, there were no charitable contributions made to the AEP Foundation. The charitable contributions to the AEP Foundation recorded in 2019 were as follows:

		Year Ended	
Company		December 31, 2019	
		(in millions)	
AEP		$	50.0 		
AEP Texas		6.2 		
AEPTCo		6.5 		
APCo		8.9 		
I&M		9.0 		
OPCo		5.4 		
PSO		3.4 		
SWEPCo		5.5 		

OKTCo Radial Assets Transfer (Applies to AEP, AEPTCo and PSO)

In August 2020, AEPSC filed a request with FERC, on behalf of PSO and OKTCo, to transfer OKTCo's interests in its radial assets to PSO. See “FERC Rate Matters” section of Note 4 for additional information.

389

17.  VARIABLE INTEREST ENTITIES AND EQUITY METHOD INVESTMENTS

The disclosures in this note apply to all Registrants unless indicated otherwise.

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE.  A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently. 

AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. AEP has not provided material financial or other support that was not previously contractually required to any of its consolidated VIEs. If an entity is determined not to be a VIE, or if the entity is determined to be a VIE and AEP is not deemed to be the primary beneficiary, the entity is accounted for under the equity method of accounting.

Consolidated Variable Interests Entities (Applies to all Registrants except AEPTCo, OPCo and PSO)

Sabine

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the years ended December 31, 2020, 2019 and 2018 were $131 million, $110 million and $152 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets.

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $155 million.  Since SWEPCo uses self-bonding, the guarantee commits SWEPCo to complete the reclamation, in the event, Sabine does not complete the work.  This guarantee ends upon completion of reclamation.  The mine end-of-life has been adjusted to March 2023, in order to align with the announced closure of the Pirkey Power Plant. Reclamation is expected to be complete by 2037 at an estimated cost of $104 million.  Actual reclamation costs could vary due to inflation and scope changes to the mine reclamation.  SWEPCo recovers these costs through its fuel clauses. As of December 31, 2020, SWEPCo has recorded $89 million of mine reclamation costs in Asset Retirement Obligations and has collected $81 million through a rider for reclamation costs. The remaining $8 million is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets.
390

DCC Fuel

I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the leases for the years ended December 31, 2020, 2019 and 2018 were $94 million, $95 million and $113 million, respectively.  The leases were recorded as finance leases on I&M’s balance sheets as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months.  Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The finance leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets.

Transition Funding

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that AEP Texas is the primary beneficiary of Transition Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Transition Funding. As of December 31, 2020 and 2019, $66 million and $267 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $209 million and $274 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets. Transition Funding has securitized transition assets of $242 million and $389 million as of December 31, 2020 and 2019, respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from AEP Texas under-recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets.

Restoration Funding

Restoration Funding was formed for the sole purpose of issuing and servicing securitization bonds related to storm restoration of AEP Texas’ distribution system primarily due to damage caused by Hurricane Harvey. Management has concluded that AEP Texas is the primary beneficiary of Restoration Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Restoration Funding. As of December 2020 and 2019, $23 million and $14 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $195 million and $221 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets. Restoration Funding has securitized assets of $205 million and $232 million as of December 31, 2020 and 2019, respectively, which are presented separately on the face of the balance sheets. The securitized restoration assets represent the right to impose and collect Texas storm restoration costs from customers receiving electric transmission or distribution service from AEP Texas under-recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Restoration Funding’s securitized assets and remits all related amounts collected from customers to Restoration Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Restoration Funding’s assets and liabilities on the balance sheets.

391

Appalachian Consumer Rate Relief Funding

Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo’s under-recovered ENEC deferral balance.  Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo’s equity interest could potentially be significant.  Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding.  As of December 31, 2020 and 2019, $25 million and $25 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $199 million and $223 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets.  Appalachian Consumer Rate Relief Funding has securitized assets of $210 million and $235 million as of December 31, 2020 and 2019, respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC.  In November 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to APCo or any other AEP entity.  APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets.

AEP Credit

AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 25% of AEP Credit’s short-term borrowing needs in excess of third-party financings. Any third-party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Securitized Accounts Receivables - AEP Credit” section of Note 14.

EIS

AEP’s subsidiaries participate in one protected cell of EIS for six lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third-parties access to this insurance. AEP’s subsidiaries and any allowed third-parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2020, 2019 and 2018 was $31 million, $34 million and $34 million, respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.

392

Transource Energy

Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. Transource Energy’s activities consist of the development, construction and operation of FERC-regulated transmission assets in Missouri, West Virginia, Pennsylvania, Maryland and Oklahoma. Transource Energy has a credit facility agreement where borrowings are loaned through intercompany lending agreements to its subsidiaries. The creditor to the agreement has no recourse to the general credit of AEP. Transource Energy’s credit facility agreement contains certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets.

Desert Sky Wind Farm LLC and Trent Wind Farm LLC

Desert Sky Wind Farm LLC and Trent Wind Farm LLC (collectively the LLCs) were established for the purpose of repowering, owning and operating wind-powered electric energy generation facilities in Texas. In January 2018, AEP admitted a nonaffiliate as a member of the LLCs to own and repower Desert Sky and Trent. The nonaffiliate contributed full turbine sets to each project in exchange for a 20.1% interest in the LLCs. The nonaffiliates’ contribution of $84 million was recorded as Net Property, Plant and Equipment on the balance sheets, which was the fair value as of the contribution date determined based on key input assumptions of the original cost of the full turbine sets and the discounted cash flow benefit associated with the production tax credits available from repowering Desert Sky and Trent based on their expected net capacity, capacity factor and the operational availability. From January 2018 through July 2020, AEP owned 79.9% of the LLCs. As a result, management concluded that the LLCs were VIEs and that AEP was the primary beneficiary based on its power to direct the activities that most significantly impact their economic performance. Also in January 2018, the LLCs entered into a forward PPA for the sale of power to AEPEP related to deliveries of electricity beginning January 1, 2021 for a 12 year period. Prior to the effective date of the PPA, the LLCs sold power at market rates into ERCOT. AEP and the nonaffiliate shared tax attributes including PTC and cash distributions from the operation of the LLCs generally consistent with the ownership percentages. See the tables below for the classification of the LLCs’ assets and liabilities on the balance sheets.

In August 2020, AEP exercised its call right which required the nonaffiliate to sell its noncontrolling interest in the LLCs to AEP. The nonaffiliates’ interest in the LLCs was presented as Redeemable Noncontrolling Interest on the balance sheets. The exercise price for the call right was determined using a discounted cash flow model with agreed input assumptions as well as updates to certain assumptions reasonably expected based on the actual results of the LLCs. As a result, the LLCs are wholly-owned by AEP and management has concluded that the LLCs are no longer VIEs. As of December 31, 2020 and 2019, AEP recorded $0 and $66 million, respectively, of Redeemable Noncontrolling Interest in Mezzanine Equity on the balance sheets.

393

Apple Blossom Wind Holdings LLC and Black Oak Getty Wind Holdings LLC

In April 2019, AEP acquired an equity interest in Apple Blossom Wind Holdings LLC (Apple Blossom) and Black Oak Getty Wind Holdings LLC (Black Oak) (collectively the Project Entities) as part of the purchase of Sempra Renewables LLC. Both of the Project Entities have long-term PPAs for 100% of their energy production. The Project Entities are tax equity partnerships with nonaffiliated noncontrolling interests to which a percentage of earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. Management has concluded that the Project Entities are VIEs and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact the Project Entities’ economic performance. In addition, AEP has not provided material financial or other support to the Project Entities that was not previously contractually required. As the primary beneficiary of the Project Entities, AEP consolidates the Project Entities into its financial statements. See the table below for the classification of Project Entities’ assets and liabilities on the balance sheets.

The nonaffiliated interests in the Project Entities is presented in Noncontrolling Interests on the balance sheets.  As of December 31, 2020 and 2019, AEP recorded $119 million and $128 million, respectively, of Noncontrolling Interests related to the Project Entities in Equity on the balance sheets.

The Project Entities’ tax equity partnerships represent substantive profit-sharing arrangements. The method for attributing income and loss to the noncontrolling interests is a balance sheet approach referred to as the hypothetical liquidation at book value (HLBV) method. Under the HLBV method, the income and loss attributable to the noncontrolling interests reflect changes in the amounts the members would hypothetically receive at each balance sheet date under the liquidation provisions of the respective limited liability company agreements, assuming the net assets of these entities were liquidated at recorded amounts, after taking into account any capital transactions, such as contributions or distributions, between the entities and the members. For the years ended December 31, 2020 and 2019, the HLBV method resulted in a loss of $6 million and $6 million, respectively, allocated to Noncontrolling Interests.

Santa Rita East

In July 2019, AEP acquired a 75% interest in Santa Rita East Wind Energy Holdings, LLC and its wholly-owned subsidiary, Santa Rita East Wind Energy, LLC (collectively, Santa Rita East). In November 2020, AEP acquired an additional 10% interest in Santa Rita East resulting in AEP having a total interest of 85%. Santa Rita East is a partnership whose sole purpose is to own and operate a 302 MW wind generation facility in west Texas. Santa Rita East delivers energy and provides renewable energy credits through three long-term PPAs totaling 260 MWs. The remaining 42 MWs of energy are sold at wholesale into ERCOT. Management has concluded that Santa Rita East is a VIE and that AEP is the primary beneficiary based on its power as managing member of the partnership to direct the activities that most significantly impact Santa Rita East’s economic performance. As the primary beneficiary of Santa Rita East, AEP consolidates Santa Rita East into its financial statements. See the table below for the classification of Santa Rita East’s assets and liabilities on the balance sheets.
AEP recognized $23 million and $10 million of PTC attributable to Santa Rita East for the years ended December 31, 2020 and 2019, respectively, which was recorded in Income Tax Expense (Benefit) on the statements of income. The nonaffiliated interest in Santa Rita East is presented in Noncontrolling Interests on the balance sheets. As of December 31, 2020 and 2019, AEP recorded $61 million and $118 million, respectively, of Noncontrolling Interests related to Santa Rita East in Equity on the balance sheets.
394

The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.

American Electric Power Company, Inc. and Subsidiary Companies	
Variable Interest Entities	
December 31, 2020	
			
	Registrant Subsidiaries		
	SWEPCo
Sabine		I&M
DCC Fuel		AEP Texas Transition Funding		AEP Texas Restoration Funding		APCo
Appalachian
Consumer
Rate
Relief Funding		
	(in millions)		
ASSETS											
Current Assets	$	88.0 			$	76.1 			$	61.2 			$	23.3 			$	16.8 			
Net Property, Plant and Equipment	97.3 			138.9 			— 			— 			— 			
Other Noncurrent Assets	99.3 			70.9 			273.9 		(a)	214.9 		(b)	212.7 		(c)	
Total Assets	$	284.6 			$	285.9 			$	335.1 			$	238.2 			$	229.5 			
											
LIABILITIES AND EQUITY											
Current Liabilities	$	57.7 			$	76.0 			$	69.8 			$	33.9 			$	28.7 			
Noncurrent Liabilities	225.3 			209.9 			246.5 			203.1 			198.9 			
Equity	1.6 			— 			18.8 			1.2 			1.9 			
Total Liabilities and Equity	$	284.6 			$	285.9 			$	335.1 			$	238.2 			$	229.5 			

(a)Includes an intercompany item eliminated in consolidation of $32 million.
(b)Includes an intercompany item eliminated in consolidation of $9 million.
(c)Includes an intercompany item eliminated in consolidation of $3 million.

American Electric Power Company, Inc. and Subsidiary Companies		
Variable Interest Entities		
December 31, 2020		
						
	Other Consolidated VIEs		
	AEP Credit		Protected
Cell
of EIS		Transource Energy		Apple Blossom and Black Oak		Santa Rita East		
	(in millions)		
ASSETS											
Current Assets	$	960.4 			$	198.1 			$	22.2 			$	9.6 			$	6.0 			
Net Property, Plant and Equipment	— 			— 			458.7 			223.1 			453.1 			
Other Noncurrent Assets	12.9 			— 			3.7 			12.1 			— 			
Total Assets	$	973.3 			$	198.1 			$	484.6 			$	244.8 			$	459.1 			
											
LIABILITIES AND EQUITY											
Current Liabilities	$	827.2 			$	43.1 			$	32.6 			$	5.3 			$	3.5 			
Noncurrent Liabilities	0.8 			62.5 			185.0 			4.9 			6.7 			
Equity	145.3 			92.5 			267.0 			234.6 			448.9 			
Total Liabilities and Equity	$	973.3 			$	198.1 			$	484.6 			$	244.8 			$	459.1 			

395

																																	
American Electric Power Company, Inc. and Subsidiary Companies	
Variable Interest Entities	
December 31, 2019	
											
	Registrant Subsidiaries		
	SWEPCo
Sabine		I&M
DCC Fuel		AEP Texas Transition Funding		AEP Texas Restoration Funding		APCo
Appalachian
Consumer
Rate
Relief Funding		
	(in millions)		
ASSETS											
Current Assets	$	80.0 			$	86.5 			$	187.0 			$	9.4 			$	21.5 			
Net Property, Plant and Equipment	111.6 			156.8 			— 			— 			— 			
Other Noncurrent Assets	93.2 			82.5 			428.1 		(a)	234.4 		(b)	237.5 		(c)	
Total Assets	$	284.8 			$	325.8 			$	615.1 			$	243.8 			$	259.0 			
											
LIABILITIES AND EQUITY											
Current Liabilities	$	50.6 			$	86.4 			$	280.2 			$	16.3 			$	28.3 			
Noncurrent Liabilities	233.6 			239.4 			316.3 			226.3 			228.8 			
Equity	0.6 			— 			18.6 			1.2 			1.9 			
Total Liabilities and Equity	$	284.8 			$	325.8 			$	615.1 			$	243.8 			$	259.0 			

(a)Includes an intercompany item eliminated in consolidation of $39 million.
(b)Includes an intercompany item eliminated in consolidation of $1 million.
(c)Includes an intercompany item eliminated in consolidation of $3 million.

American Electric Power Company, Inc. and Subsidiary Companies		
Variable Interest Entities		
December 31, 2019		
													
	Other Consolidated VIEs		
	AEP Credit		Protected
Cell
of EIS		Transource Energy		Desert Sky
and
Trent		Apple Blossom and Black Oak		Santa Rita East		
	(in millions)		
ASSETS													
Current Assets	$	842.8 			$	194.6 			$	25.8 			$	7.8 			$	10.1 			$	17.7 			
Net Property, Plant and Equipment	— 			— 			424.1 			330.6 			231.4 			465.2 			
Other Noncurrent Assets	7.1 			— 			3.2 			10.1 			13.1 			0.3 			
Total Assets	$	849.9 			$	194.6 			$	453.1 			$	348.5 			$	254.6 			$	483.2 			
													
LIABILITIES AND EQUITY													
Current Liabilities	$	805.2 			$	40.7 			$	192.4 			$	5.5 			$	5.4 			$	3.9 			
Noncurrent Liabilities	0.9 			78.0 			4.8 			15.8 			4.7 			7.5 			
Equity	43.8 			75.9 			255.9 			327.2 			244.5 			471.8 			
Total Liabilities and Equity	$	849.9 			$	194.6 			$	453.1 			$	348.5 			$	254.6 			$	483.2 			

396

Non-Consolidated Significant Variable Interests

DHLC

DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  The operations of DHLC are governed by the lignite mining agreement among SWEPCo, CLECO and DHLC. SWEPCo and CLECO share the executive board seats and voting rights equally. In accordance with the lignite mining agreement, each entity is responsible for 50% of DHLC’s obligations, including debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the years ended December 31, 2020, 2019 and 2018 were $142 million, $55 million and $58 million, respectively.  SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC.  SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets.
SWEPCo’s investment in DHLC was:

	December 31,	
	2020		2019	
	As Reported on
the Balance Sheet		Maximum
Exposure		As Reported on
the Balance Sheet		Maximum
Exposure	
	(in millions)	
Capital Contribution from SWEPCo	$	7.6 			$	7.6 			$	7.6 			$	7.6 		
Retained Earnings	20.4 			20.4 			17.5 			17.5 		
SWEPCo’s Share of Obligations	— 			98.5 			— 			130.0 		
Total Investment in DHLC	$	28.0 			$	126.5 			$	25.1 			$	155.1 		

OVEC

AEP and several nonaffiliated utility companies jointly own OVEC.  As of December 31, 2020, AEP’s ownership in OVEC was 43.47%. Parent owns 39.17% and OPCo owns 4.3%. APCo, I&M and OPCo are members to an intercompany power agreement.  The Registrants’ power participation ratios are 15.69% for APCo, 7.85% for I&M and 19.93% for OPCo. Participants of this agreement are entitled to receive and are obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs, including outstanding indebtedness, and provide a return on capital.  The intercompany power agreement ends in June 2040.
 
AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants.  These environmental projects were funded through debt issuances. As of December 31, 2020 and 2019, OVEC’s outstanding indebtedness was approximately $1.3 billion and $1.4 billion, respectively. Although they are not an obligor or guarantor, the Registrants’ are responsible for their respective ratio of OVEC’s outstanding debt through the intercompany power agreement. Principal and interest payments related to OVEC’s outstanding indebtedness are disclosed in accordance with the accounting guidance for “Commitments.” See the “Commitments” section of Note 6 for additional information.

AEP is not required to consolidate OVEC as it is not the primary beneficiary, although AEP and its subsidiary holds a significant variable interest in OVEC. Power to control decision making that significantly impacts the economic performance of OVEC is shared amongst the owners through their representation on the Board of Directors of OVEC and the representation of the sponsoring companies on the Operating Committee under the intercompany power agreement.

397

AEP’s investment in OVEC was:

	December 31,	
	2020		2019	
	As Reported on
the Balance Sheet		Maximum
Exposure		As Reported on
the Balance Sheet		Maximum Exposure	
	(in millions)	
Capital Contribution from AEP	$	4.4 			$	4.4 			$	4.4 			$	4.4 		
AEP’s Ratio of OVEC Debt (a)	— 			555.0 			— 			588.9 		
Total Investment in OVEC	$	4.4 			$	559.4 			$	4.4 			$	593.3 		

(a)Based on the Registrants’ power participation ratios APCo, I&M and OPCo’s share of OVEC debt was $200 million, $100 million and $255 million as of December 31, 2020 and $213 million, $106 million and $270 million as of December 31, 2019, respectively.

Power purchased by the Registrant Subsidiaries from OVEC is included in Purchased Electricity for Resale on the statements of income and is shown in the table below:

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
APCo		$	94.4 			$	104.5 			$	100.4 		
I&M		47.2 			52.3 			50.2 		
OPCo		120.8 			132.7 			127.5 		

AEPSC

AEPSC provides certain managerial and professional services to AEP’s subsidiaries.  Parent is the sole equity owner of AEPSC.  AEP management controls the activities of AEPSC.  The costs of the services are based on a direct-charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost.  AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered.  AEPSC finances its operations through cost reimbursement from other AEP subsidiaries.  There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business.  AEPSC and its billings are subject to regulation by the FERC.  AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations.  AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure.  However, AEP subsidiaries do not have control over AEPSC.  AEPSC is consolidated by AEP.  In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

398

Total AEPSC billings to the Registrant Subsidiaries were as follows:

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
AEP Texas		$	199.4 			$	206.6 			$	184.3 		
AEPTCo		270.3 			242.3 			220.4 		
APCo		294.9 			308.3 			295.6 		
I&M		210.2 			184.8 			173.5 		
OPCo		232.8 			230.4 			214.9 		
PSO		113.2 			125.7 			121.5 		
SWEPCo		161.8 			169.5 			164.4 		

The carrying amount and classification of variable interest in AEPSC’s accounts payable were as follows:

		December 31,	
		2020		2019	
Company		As Reported on
the Balance Sheet		Maximum
Exposure		As Reported on
the Balance Sheet		Maximum
Exposure	
		(in millions)	
AEP Texas		$	30.5 			$	30.5 			$	32.4 			$	32.4 		
AEPTCo		45.9 			45.9 			33.4 			33.4 		
APCo		42.8 			42.8 			44.1 			44.1 		
I&M		27.1 			27.1 			28.6 			28.6 		
OPCo		33.9 			33.9 			33.2 			33.2 		
PSO		15.7 			15.7 			18.1 			18.1 		
SWEPCo		22.0 			22.0 			23.4 			23.4 		

AEGCo

AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP.  AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1 and leases a 50% interest in Rockport Plant, Unit 2. AEGCo sells all the output from the Rockport Plant to I&M and KPCo.  AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo.  I&M is considered to have a significant interest in AEGCo due to these transactions.  I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations.  In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2020, 2019 and 2018 were $173 million, $215 million and $238 million, respectively. The carrying amounts of I&M’s liabilities associated with AEGCo as of December 31, 2020 and 2019 were $9 million and $10 million, respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. See “Rockport Lease” section of Note 13 for additional information.

399

Significant Equity Method Investments in Unconsolidated Entities

For a discussion of the equity method of accounting, see the “Equity Investment in Unconsolidated Entities” section of Note 1.

Sempra Renewables LLC

In April 2019, AEP acquired a 50% interest in five wind farms in multiple states as part of the purchase of Sempra Renewables LLC. The wind farms are joint ventures with BP Wind Energy who holds the other 50% interest. All five wind farms have long-term PPAs for 100% of their energy production. One of the jointly-owned wind farms has PPAs with I&M and OPCo for a portion of its energy production. Another jointly-owned wind farm has a PPA with SWEPCo for a portion of its energy production. The joint venture wind farms are not considered VIEs and AEP is not required to consolidate them as AEP does not have a controlling financial interest. However, AEP is able to exercise significant influence over the wind farms and therefore applies the equity method of accounting. As of December 31, 2020 and 2019, AEP’s investment in the five joint venture wind farms was $376 million and $394 million, respectively. The investment includes amounts recognized in AOCI related to interest rate cash flow hedges. The investment is comprised of a historical investment of $399 million plus a basis difference of $(12) million. AEP’s equity earnings associated with the five joint venture wind farms was $2 million and a loss of $4 million for the years ended December 31, 2020 and 2019, respectively. AEP recognized $36 million and $27 million of PTC attributable to the joint venture wind farms for the years ended December 31, 2020 and 2019, respectively, which was recorded in Income Tax Expense (Benefit) on the statements of income.

ETT

ETT designs, acquires, constructs, owns and operates certain transmission facilities in ERCOT. Berkshire Hathaway Energy, a nonaffiliated entity, holds a 50% membership interest in ETT and AEP Transmission Holdco holds a 50% membership interest in ETT. As a result, AEP, through its wholly-owned subsidiary, holds a 50% membership interest in ETT. As of December 31, 2020 and 2019, AEP’s investment in ETT was $732 million and $695 million, respectively. AEP’s equity earnings associated with ETT were $68 million, $66 million and $62 million for the years ended December 31, 2020, 2019 and 2018 respectively.

400

18.  PROPERTY, PLANT AND EQUIPMENT

The disclosures in this note apply to all Registrants unless indicated otherwise.

Property, Plant and Equipment is shown functionally on the face of the balance sheets. The following tables include the total plant balances as of December 31, 2020 and 2019:

December 31, 2020		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo		
		(in millions)		
Regulated Property, Plant and Equipment																		
Generation		$	21,587.8 		(a)	$	— 			$	— 			$	6,633.7 			$	5,264.7 			$	— 			$	1,480.7 			$	4,681.4 		(a)	
Transmission		27,841.5 			5,279.6 			9,593.5 			3,900.5 			1,696.4 			2,831.9 			1,069.9 			2,165.7 			
Distribution		23,972.1 			4,580.8 			— 			4,464.3 			2,594.6 			5,708.3 			2,853.0 			2,382.5 			
Other		4,852.4 			866.0 			328.8 			598.0 			644.6 			888.5 			388.1 			564.5 			
CWIP		3,815.0 		(a)	614.1 			1,422.6 			484.6 			362.4 			362.3 			128.7 			228.3 		(a)	
Less: Accumulated Depreciation		20,094.2 			1,528.1 			572.8 			4,711.0 			3,538.6 			2,348.8 			1,607.3 			3,032.0 			
Total Regulated Property, Plant and Equipment - Net		61,974.6 			9,812.4 			10,772.1 			11,370.1 			7,024.1 			7,442.2 			4,313.1 			6,990.4 			
Nonregulated Property, Plant and Equipment - Net		1,927.0 			1.2 			0.7 			24.0 			28.2 			9.9 			6.9 			97.8 			
Total Property, Plant and Equipment - Net		$	63,901.6 			$	9,813.6 			$	10,772.8 			$	11,394.1 			$	7,052.3 			$	7,452.1 			$	4,320.0 			$	7,088.2 			

December 31, 2019		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo		
		(in millions)		
Regulated Property, Plant and Equipment																		
Generation		$	21,323.5 		(a)	$	— 			$	— 			$	6,563.7 			$	5,099.7 			$	— 			$	1,574.6 			$	4,691.4 		(a)	
Transmission		24,763.4 			4,466.5 			8,137.9 			3,584.1 			1,641.8 			2,686.3 			948.5 			2,056.5 			
Distribution		22,440.8 			4,215.2 			— 			4,201.7 			2,437.6 			5,323.5 			2,684.8 			2,270.7 			
Other		4,369.6 			803.4 			268.2 			542.0 			590.9 			754.7 			337.2 			520.6 			
CWIP		4,261.2 		(a)	763.9 			1,485.7 			593.4 			382.3 			394.4 			133.4 			210.1 		(a)	
Less: Accumulated Depreciation		18,778.1 			1,465.0 			402.3 			4,425.6 			3,281.4 			2,261.7 			1,579.9 			2,766.2 			
Total Regulated Property, Plant and Equipment - Net		58,380.4 			8,784.0 			9,489.5 			11,059.3 			6,870.9 			6,897.2 			4,098.6 			6,983.1 			
Nonregulated Property, Plant and Equipment - Net		1,757.7 			61.1 			1.4 			22.6 			28.8 			9.8 			4.7 			112.1 			
Total Property, Plant and Equipment - Net		$	60,138.1 			$	8,845.1 			$	9,490.9 			$	11,081.9 			$	6,899.7 			$	6,907.0 			$	4,103.3 			$	7,095.2 			

(a)AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.

401

Depreciation, Depletion and Amortization

The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.  The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants:

AEP																									
		2020		2019		2018	
Functional Class of Property		Annual Composite
Depreciation Rate Ranges		Depreciable
Life Ranges		Annual Composite
Depreciation Rate Ranges		Depreciable
Life Ranges		Annual Composite
Depreciation Rate Ranges		Depreciable
Life Ranges	
						(in years)						(in years)						(in years)	
Generation		2.7%	-	6.3%		20	-	132		2.5%	-	5.5%		20	-	132		2.4%	-	4.0%		20	-	132	
Transmission		2.0%	-	2.6%		15	-	75		1.8%	-	2.6%		15	-	81		1.6%	-	2.7%		15	-	81	
Distribution		2.7%	-	3.7%		7	-	78		2.7%	-	3.7%		7	-	78		2.7%	-	3.6%		7	-	78	
Other		2.8%	-	11.3%		5	-	75		2.6%	-	9.5%		5	-	75		2.3%	-	9.8%		5	-	75	

AEP Texas																			
		2020		2019		2018	
Functional Class of Property		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges	
				(in years)				(in years)				(in years)	
Transmission		2.0%		50	-	75		1.8%		45	-	81		1.7%		45	-	81	
Distribution		3.1%		7	-	70		3.5%		7	-	70		3.6%		7	-	70	
Other		6.1%		5	-	50		6.3%		5	-	50		6.0%		5	-	50	

AEPTCo																			
		2020		2019		2018	
Functional Class of Property		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges	
				(in years)				(in years)				(in years)	
Transmission		2.4%		24	-	75		2.0%		24	-	75		1.9%		20	-	75	
Other		6.3%		5	-	64		5.8%		5	-	64		5.6%		5	-	64	

APCo																			
		2020		2019		2018	
Functional Class of Property		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges	
				(in years)				(in years)				(in years)	
Generation		3.3%		35	-	118		3.2%		35	-	118		3.1%		35	-	112	
Transmission		2.2%		15	-	75		1.8%		15	-	71		1.6%		15	-	68	
Distribution		3.7%		12	-	57		3.7%		12	-	57		3.6%		10	-	57	
Other		7.8%		5	-	55		7.2%		5	-	55		7.4%		5	-	55	

I&M																			
		2020		2019		2018	
Functional Class of Property		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges	
				(in years)				(in years)				(in years)	
Generation		4.6%		20	-	132		4.0%		20	-	132		3.4%		20	-	132	
Transmission		2.3%		45	-	70		1.9%		50	-	73		1.8%		50	-	73	
Distribution		3.4%		14	-	71		3.4%		9	-	75		3.1%		9	-	75	
Other		10.2%		5	-	51		9.4%		5	-	50		8.9%		5	-	50	

OPCo																			
		2020		2019		2018	
Functional Class of Property		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges	
				(in years)				(in years)				(in years)	
Transmission		2.3%		39	-	60		2.3%		39	-	60		2.3%		39	-	60	
Distribution		3.1%		14	-	65		3.1%		14	-	65		3.0%		14	-	65	
Other		5.0%		5	-	50		4.9%		5	-	50		6.3%		5	-	50	
402

																																																									
PSO																			
		2020		2019		2018	
Functional Class of Property		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges	
				(in years)				(in years)				(in years)	
Generation		3.1%		35	-	75		2.9%		35	-	75		2.9%		35	-	75	
Transmission		2.2%		45	-	75		2.4%		45	-	75		2.3%		45	-	75	
Distribution		2.9%		15	-	78		2.9%		15	-	78		2.9%		15	-	78	
Other		5.7%		5	-	64		5.6%		5	-	64		6.3%		5	-	64	

SWEPCo																			
		2020		2019		2018	
Functional Class of Property		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges		Annual Composite
Depreciation Rate		Depreciable
Life Ranges	
				(in years)				(in years)				(in years)	
Generation		2.7%		35	-	65		2.5%		40	-	70		2.4%		40	-	70	
Transmission		2.3%		47	-	73		2.4%		50	-	73		2.2%		50	-	73	
Distribution		2.7%		15	-	67		2.7%		25	-	70		2.7%		25	-	70	
Other		8.5%		5	-	52		7.6%		5	-	55		8.0%		5	-	55	

The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property of AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo for 2020, 2019 and 2018.

		2020		2019		2018		
Functional Class of Property		Annual Composite
Depreciation Rate Ranges		Depreciable
Life Ranges		Annual Composite
Depreciation Rate Ranges		Depreciable
Life Ranges		Annual Composite
Depreciation Rate Ranges		Depreciable
Life Ranges		
						(in years)						(in years)						(in years)		
Generation		3.6%	-	4.0%		15	-	59		3.2%	-	21.2%		15	-	59		3.4%	-	22.3%		15	-	59		
Transmission		2.5%		30	-	40		2.5%		30	-	40		2.4%		40		
Distribution		NA		NA		2.3%		40		2.3%		40		
Other		16.1%		5	-	50	(a)	17.6%		5	-	50	(a)	16.3%		5	-	50	(a)	

(a)SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years.
NA Not applicable.

SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment.  SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages.  SWEPCo includes these costs in fuel expense.

For regulated operations, the composite depreciation rate generally includes a component for non-ARO removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets.  Actual removal costs incurred are charged to Accumulated Depreciation and Amortization.  Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability.  For nonregulated operations, non-ARO removal costs are expensed as incurred. 

Asset Retirement Obligations (Applies to all Registrants except AEPTCo)

The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal-mining facilities.  I&M records ARO for the decommissioning of the Cook Plant.  The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned.  Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use.  The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely.  The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.

403

The Registrants recorded the following revisions to ARO estimates as of December 31, 2020:

•In March 2020, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million primarily due to the revision in the useful life of DHLC. See Note 5 - Effects of Regulation for additional information. In September 2020, SWEPCo recorded an $18 million revision due to a reduction in estimated ash pond closure costs.
•In June 2020, AEP Texas and PSO recorded a revision to decrease estimated ARO liabilities by $17 million and $5 million, respectively, due to the retirement of the Oklaunion Power Station in September 2020. See Note 5 - Effects of Regulation for additional information.
•In June 2020, AGR derecognized $106 million of Conesville Plant related ARO liabilities as a result of the Environmental Liability and Property Transfer and Asset Purchase Agreement executed with a non-affiliated third-party. See Note 7 - Acquisitions and Dispositions for additional information.
•In June 2020, APCo recorded a revision to increase estimated Glen Lyn Station ash disposal ARO liabilities by $199 million due to the enactment of House Bill 443. This bill requires APCo to close the ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. The legislation provides for regulatory recovery of these costs. See Note 6 - Commitments, Guarantees and Contingencies for additional information.

As of December 31, 2020 and 2019, I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.80 billion and $1.73 billion, respectively.  These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets.  As of December 31, 2020 and 2019, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $2.98 billion and $2.65 billion, respectively.  These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets.

The following is a reconciliation of the 2020 and 2019 aggregate carrying amounts of ARO by Registrant:

Company		ARO as of December 31, 2019		Accretion
Expense		Liabilities
Incurred		Liabilities
Settled		Revisions in
Cash Flow
Estimates (a)		ARO as of December 31, 2020	
		(in millions)	
AEP (b)(c)(d)(e)		$	2,418.9 			$	102.4 			$	0.3 			$	(188.0)			$	183.1 			$	2,516.7 		
AEP Texas (b)(e)		29.1 			0.8 			— 			(8.5)			(16.8)			4.6 		
APCo (b)(e)		111.1 			8.9 			— 			(7.8)			200.9 			313.1 		
I&M (b)(c)(e)		1,748.6 			70.2 			0.1 			(0.2)			(4.9)			1,813.8 		
OPCo (e)		1.8 			0.1 			— 			— 			— 			1.9 		
PSO (b)(e)		52.2 			3.1 			— 			(3.1)			(4.8)			47.4 		
SWEPCo (b)(d)(e)		212.2 			10.7 			— 			(10.9)			10.1 			222.1 		

																																							
Company		ARO as of December 31, 2018		Accretion
Expense		Liabilities
Incurred		Liabilities
Settled		Revisions in
Cash Flow
Estimates (a)		ARO as of December 31, 2019	
		(in millions)	
AEP (b)(c)(d)(e)		$	2,355.5 			$	102.5 			$	12.0 			$	(118.1)			$	67.0 			$	2,418.9 		
AEP Texas (b)(e)		27.9 			1.3 			— 			(0.2)			0.1 			29.1 		
APCo (b)(e)		116.1 			5.9 			— 			(17.6)			6.7 			111.1 		
I&M (b)(c)(e)		1,681.3 			67.4 			— 			(0.2)			0.1 			1,748.6 		
OPCo (e)		1.8 			0.1 			— 			(0.3)			0.2 			1.8 		
PSO (b)(e)		46.9 			3.1 			— 			(0.4)			2.6 			52.2 		
SWEPCo (b)(d)(e)		206.8 			10.3 			— 			(11.8)			6.9 			212.2 		

(a)Unless discussed above, primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs.
(b)Includes ARO related to ash disposal facilities.
(c)Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.80 billion and $1.73 billion as of December 31, 2020 and 2019, respectively.
(d)Includes ARO related to Sabine and DHLC.
404

(e)Includes ARO related to asbestos removal.

Allowance for Funds Used During Construction and Interest Capitalization

The Registrants’ amounts of Allowance for Equity Funds Used During Construction are summarized in the following table:

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
AEP		$	148.1 			$	168.4 			$	132.5 		
AEP Texas		19.4 			15.2 			20.0 		
AEPTCo		74.0 			84.3 			70.6 		
APCo		14.6 			16.6 			13.2 		
I&M		11.5 			19.4 			11.9 		
OPCo		12.5 			18.2 			9.8 		
PSO		4.0 			2.7 			0.4 		
SWEPCo		7.7 			6.8 			6.0 		

The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table:

		Years Ended December 31,	
Company		2020		2019		2018	
		(in millions)	
AEP		$	66.0 			$	88.7 			$	73.6 		
AEP Texas		12.5 			20.0 			18.4 		
AEPTCo		25.5 			32.2 			26.1 		
APCo		7.9 			9.3 			8.4 		
I&M		5.7 			8.9 			7.4 		
OPCo		6.2 			6.7 			5.8 		
PSO		2.0 			1.9 			0.9 		
SWEPCo		3.9 			4.0 			4.8 		

405

Jointly-owned Electric Facilities (Applies to AEP, AEP Texas, I&M, PSO and SWEPCo)

The Registrants have electric facilities that are jointly-owned with affiliated and nonaffiliated companies.  Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest.  Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows:

					Registrant’s Share as of December 31, 2020	
	Fuel
Type		Percent of
Ownership		Utility Plant
in Service		Construction
Work in
Progress		Accumulated
Depreciation	
					(in millions)	
AEP										
Dolet Hills Power Station, Unit 1 (a)	Lignite		40.2 	%		$	342.4 			$	4.6 			$	295.4 		
Flint Creek Generating Station, Unit 1 (b)	Coal		50.0 	%		377.2 			3.0 			116.0 		
Pirkey Power Plant, Unit 1 (b)	Lignite		85.9 	%		602.8 			3.7 			441.0 		
Oklaunion Power Station (f)(g)	Coal		70.3 	%		— 			— 			— 		
Turk Generating Plant (b)	Coal		73.3 	%		1,594.3 			2.8 			257.3 		
Total					$	2,916.7 			$	14.1 			$	1,109.7 		
										
AEP Texas										
Oklaunion Power Station (f)(g)	Coal		54.7 	%		$	— 			$	— 			$	— 		
										
I&M										
Rockport Generating Plant (c)(d)(e)	Coal		50.0 	%		$	1,228.5 			$	19.6 			$	677.3 		
										
PSO										
Oklaunion Power Station (f)(g)	Coal		15.6 	%		$	— 			$	— 			$	— 		
										
SWEPCo										
Dolet Hills Power Station, Unit 1 (a)	Lignite		40.2 	%		$	342.4 			$	4.6 			$	295.4 		
Flint Creek Generating Station, Unit 1 (b)	Coal		50.0 	%		377.2 			3.0 			116.0 		
Pirkey Power Plant, Unit 1 (b)	Lignite		85.9 	%		602.8 			3.7 			441.0 		
Turk Generating Plant (b)	Coal		73.3 	%		1,594.3 			2.8 			257.3 		
Total					$	2,916.7 			$	14.1 			$	1,109.7 		
406

																														
					Registrant’s Share as of December 31, 2019	
	Fuel
Type		Percent of
Ownership		Utility Plant
in Service		Construction
Work in
Progress		Accumulated
Depreciation	
					(in millions)	
AEP										
Dolet Hills Power Station, Unit 1 (a)	Lignite		40.2 	%		$	337.3 			$	6.2 			$	216.5 		
Flint Creek Generating Station, Unit 1 (b)	Coal		50.0 	%		374.3 			3.4 			101.1 		
Pirkey Power Plant, Unit 1 (b)	Lignite		85.9 	%		607.8 			7.7 			416.8 		
Oklaunion Power Station (f)(g)	Coal		70.3 	%		106.6 			0.1 			91.7 		
Turk Generating Plant (b)	Coal		73.3 	%		1,593.3 			1.7 			225.8 		
Total					$	3,019.3 			$	19.1 			$	1,051.9 		
										
AEP Texas										
Oklaunion Power Station (f)(g)	Coal		54.7 	%		$	351.7 			$	— 			$	291.9 		
										
I&M										
Rockport Generating Plant (c)(d)(e)	Coal		50.0 	%		$	1,114.2 			$	105.5 			$	586.2 		
										
PSO										
Oklaunion Power Station (f)(g)	Coal		15.6 	%		$	106.6 			$	0.1 			$	91.7 		
										
SWEPCo										
Dolet Hills Power Station, Unit 1 (a)	Lignite		40.2 	%		$	337.3 			$	6.2 			$	216.5 		
Flint Creek Generating Station, Unit 1 (b)	Coal		50.0 	%		374.3 			3.4 			101.1 		
Pirkey Power Plant, Unit 1 (b)	Lignite		85.9 	%		607.8 			7.7 			416.8 		
Turk Generating Plant (b)	Coal		73.3 	%		1,593.3 			1.7 			225.8 		
Total					$	2,912.7 			$	19.0 			$	960.2 		

(a)Operated by CLECO, a nonaffiliated company.
(b)Operated by SWEPCo.
(c)Operated by I&M.
(d)Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a nonaffiliated company. See the “Rockport Lease” section of Note 13 for additional information.
(e)AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2.
(f)Operated by PSO, which owned 15.6%. Also was jointly-owned (54.7%) by AEP Texas and various nonaffiliated companies.
(g)Oklaunion Power Station was retired in September 2020 and sold to a nonaffiliated third-party in October 2020. See the “Dispositions” section of Note 7 for additional information.

407

19. REVENUE FROM CONTRACTS WITH CUSTOMERS

The disclosures in this note apply to all Registrants, unless indicated otherwise.

Disaggregated Revenues from Contracts with Customers
The table below represents AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:

		Year Ended December 31, 2020	
		Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other		Reconciling Adjustments		AEP Consolidated	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	3,606.8 			$	2,086.9 			$	— 			$	— 			$	— 			$	— 			$	5,693.7 		
Commercial Revenues		2,016.2 			1,048.6 			— 			— 			— 			— 			3,064.8 		
Industrial Revenues		2,018.0 			390.1 			— 			— 			— 			(0.7)			2,407.4 		
Other Retail Revenues		155.6 			42.5 			— 			— 			— 			— 			198.1 		
Total Retail Revenues		7,796.6 			3,568.1 			— 			— 			— 			(0.7)			11,364.0 		
															
Wholesale and Competitive Retail Revenues:															
Generation Revenues		588.3 			— 			— 			131.9 			— 			— 			720.2 		
	
Transmission Revenues (a)		334.5 			467.0 			1,257.0 			— 			— 			(1,006.7)			1,051.8 		
	
Renewable Generation Revenues (b)		— 			— 			— 			60.9 			— 			(1.6)			59.3 		
Retail, Trading and Marketing Revenues (c)		— 			— 			— 			1,486.9 			(5.5)			(103.0)			1,378.4 		
Total Wholesale and Competitive Retail Revenues		922.8 			467.0 			1,257.0 			1,679.7 			(5.5)			(1,111.3)			3,209.7 		
															
Other Revenues from Contracts with Customers (b)		163.2 			157.8 			22.4 			2.3 			92.5 			(148.6)			289.6 		

Total Revenues from Contracts with Customers		8,882.6 			4,192.9 			1,279.4 			1,682.0 			87.0 			(1,260.6)			14,863.3 		
															
Other Revenues:															
Alternative Revenues (b)		(3.2)			70.0 			(80.6)			— 			— 			7.5 			(6.3)		
Other Revenues (b)		— 			83.0 			— 			43.6 			9.8 			(74.9)			61.5 		
	
Total Other Revenues		(3.2)			153.0 			(80.6)			43.6 			9.8 			(67.4)			55.2 		
															
Total Revenues		$	8,879.4 			$	4,345.9 			$	1,198.8 			$	1,725.6 			$	96.8 			$	(1,328.0)			$	14,918.5 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $965 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $103 million. The remaining affiliated amounts were immaterial.
408

																																													
		Year Ended December 31, 2019	
		Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other		Reconciling Adjustments		AEP Consolidated	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	3,643.7 			$	2,069.9 			$	— 			$	— 			$	— 			$	— 			$	5,713.6 		
Commercial Revenues		2,155.3 			1,152.9 			— 			— 			— 			— 			3,308.2 		
Industrial Revenues		2,179.0 			429.1 			— 			— 			— 			(0.9)			2,607.2 		
Other Retail Revenues		179.1 			43.8 			— 			— 			— 			— 			222.9 		
Total Retail Revenues		8,157.1 			3,695.7 			— 			— 			— 			(0.9)			11,851.9 		
															
Wholesale and Competitive Retail Revenues:															
Generation Revenues		807.6 			— 			— 			254.8 			— 			— 			1,062.4 		
	
Transmission Revenues (a)		292.1 			435.1 			1,077.2 			— 			— 			(825.0)			979.4 		
	
Renewable Generation Revenues (b)		— 			— 			— 			57.3 			— 			— 			57.3 		
Retail, Trading and Marketing Revenues (c)		— 			— 			— 			1,480.7 			— 			(135.6)			1,345.1 		
Total Wholesale and Competitive Retail Revenues		1,099.7 			435.1 			1,077.2 			1,792.8 			— 			(960.6)			3,444.2 		
															
Other Revenues from Contracts with Customers (b)		168.2 			169.4 			16.6 			4.9 			104.7 			(147.1)			316.7 		

Total Revenues from Contracts with Customers		9,425.0 			4,300.2 			1,093.8 			1,797.7 			104.7 			(1,108.6)			15,612.8 		
															
Other Revenues:															
Alternative Revenues (b)		(57.9)			32.3 			(20.6)			— 			— 			(66.9)			(113.1)		
Other Revenues (b)		— 			150.0 			— 			59.9 			(8.9)			(139.3)			61.7 		
	
Total Other Revenues		(57.9)			182.3 			(20.6)			59.9 			(8.9)			(206.2)			(51.4)		
															
Total Revenues		$	9,367.1 			$	4,482.5 			$	1,073.2 			$	1,857.6 			$	95.8 			$	(1,314.8)			$	15,561.4 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $794 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $136 million. The remaining affiliated amounts were immaterial.

409

																																													
		Year Ended December 31, 2018	
		Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other		Reconciling Adjustments		AEP Consolidated	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	3,751.8 			$	2,189.4 			$	— 			$	— 			$	— 			$	— 			$	5,941.2 		
Commercial Revenues		2,183.4 			1,251.7 			— 			— 			— 			— 			3,435.1 		
Industrial Revenues		2,212.8 			512.5 			— 			— 			— 			— 			2,725.3 		
Other Retail Revenues		183.5 			42.7 			— 			— 			— 			— 			226.2 		
Total Retail Revenues (a)		8,331.5 			3,996.3 			— 			— 			— 			— 			12,327.8 		
															
Wholesale and Competitive Retail Revenues:															
Generation Revenues		899.8 			— 			— 			423.7 			— 			(7.3)		(e)	1,316.2 		
	
Transmission Revenues (b)		282.2 			372.1 			849.3 			— 			— 			(737.1)			766.5 		
	
Renewable Generation Revenues (c)		— 			— 			— 			50.8 			— 			— 			50.8 		
Retail, Trading and Marketing Revenues (d)		— 			— 			— 			1,422.9 			— 			(120.7)			1,302.2 		
Total Wholesale and Competitive Retail Revenues		1,182.0 			372.1 			849.3 			1,897.4 			— 			(865.1)			3,435.7 		
															
Other Revenues from Contracts with Customers (c)		158.4 			204.6 			15.2 			20.6 			86.2 			(32.0)			453.0 		

Total Revenues from Contracts with Customers		9,671.9 			4,573.0 			864.5 			1,918.0 			86.2 			(897.1)			16,216.5 		
															
Other Revenues:															
Alternative Revenues (c)		(15.9)			(22.2)			(60.4)			— 			— 			52.7 			(45.8)		
Other Revenues (c)		(10.5)			102.3 			— 			22.3 			8.9 			(98.0)		(e)	25.0 		
	
Total Other Revenues		(26.4)			80.1 			(60.4)			22.3 			8.9 			(45.3)			(20.8)		
															
Total Revenues		$	9,645.5 			$	4,653.1 			$	804.1 			$	1,940.3 			$	95.1 			$	(942.4)			$	16,195.7 		
(a)2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $643 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $121 million. The remaining affiliated amounts were immaterial.
(e)2018 amounts have been revised to reflect the reclassification of $98 million of affiliated revenues between Generation Revenues and Other Revenues. This reclassification did not impact previously reported Total Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

410

The table below represents revenues from contracts with customers, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries:

		Year Ended December 31, 2020	
		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	563.6 			$	— 			$	1,250.6 			$	794.1 			$	1,523.4 			$	579.4 			$	630.8 		
Commercial Revenues		366.7 			— 			517.0 			499.3 			682.0 			320.1 			466.7 		
Industrial Revenues		120.1 			— 			553.5 			547.4 			270.0 			221.1 			328.8 		
Other Retail Revenues		29.5 			— 			67.6 			6.6 			13.1 			66.0 			9.1 		
Total Retail Revenues		1,079.9 			— 			2,388.7 			1,847.4 			2,488.5 			1,186.6 			1,435.4 		
															
Wholesale Revenues:															
Generation Revenues (a)		— 			— 			230.2 			274.6 			— 			15.1 			162.0 		
	
Transmission Revenues (b)		399.9 			1,210.3 			130.8 			29.0 			67.0 			27.5 			111.2 		
	
Total Wholesale Revenues		399.9 			1,210.3 			361.0 			303.6 			67.0 			42.6 			273.2 		
															
Other Revenues from Contracts with Customers (c)		48.2 			22.4 			59.5 			85.0 			109.5 			34.7 			26.7 		

Total Revenues from Contracts with Customers		1,528.0 			1,232.7 			2,809.2 			2,236.0 			2,665.0 			1,263.9 			1,735.3 		
															
Other Revenues:															
Alternative Revenues (d)		3.4 			(87.0)			(13.0)			5.8 			66.6 			2.2 			3.2 		
Other Revenues (d)		87.5 			— 			— 			— 			17.5 			— 			— 		
	
Total Other Revenues		90.9 			(87.0)			(13.0)			5.8 			84.1 			2.2 			3.2 		
															
Total Revenues		$	1,618.9 			$	1,145.7 			$	2,796.2 			$	2,241.8 			$	2,749.1 			$	1,266.1 			$	1,738.5 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $112 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $952 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $69 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.

411

																																													
		Year Ended December 31, 2019	
		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	571.5 			$	— 			$	1,266.9 			$	730.0 			$	1,502.0 			$	650.2 			$	638.6 		
Commercial Revenues		411.5 			— 			559.9 			494.2 			738.5 			388.5 			485.4 		
Industrial Revenues		129.4 			— 			592.2 			550.7 			299.9 			303.5 			338.7 		
Other Retail Revenues		29.9 			— 			75.2 			7.3 			13.1 			81.6 			9.0 		
Total Retail Revenues		1,142.3 			— 			2,494.2 			1,782.2 			2,553.5 			1,423.8 			1,471.7 		
															
Wholesale Revenues:															
Generation Revenues (a)		— 			— 			251.5 			402.4 			— 			39.5 			194.7 		
	
Transmission Revenues (b)		379.2 			1,025.5 			103.6 			25.1 			56.0 			27.5 			106.7 		
	
Total Wholesale Revenues		379.2 			1,025.5 			355.1 			427.5 			56.0 			67.0 			301.4 		
															
Other Revenues from Contracts with Customers (c)		30.1 			16.6 			61.8 			98.4 			139.3 			22.0 			26.1 		

Total Revenues from Contracts with Customers		1,551.6 			1,042.1 			2,911.1 			2,308.1 			2,748.8 			1,512.8 			1,799.2 		
															
Other Revenues:															
Alternative Revenues (d)		0.6 			(20.7)			13.6 			(1.4)			31.7 			(31.0)			(48.3)		
Other Revenues (d)		157.1 			— 			— 			— 			17.1 			— 			— 		
	
Total Other Revenues		157.7 			(20.7)			13.6 			(1.4)			48.8 			(31.0)			(48.3)		
															
Total Revenues		$	1,709.3 			$	1,021.4 			$	2,924.7 			$	2,306.7 			$	2,797.6 			$	1,481.8 			$	1,750.9 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $129 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $782 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $73 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.

412

																																													
		Year Ended December 31, 2018	
		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	578.9 			$	— 			$	1,342.7 			$	730.0 			$	1,611.6 			$	659.0 			$	641.6 		
Commercial Revenues		414.7 			— 			580.4 			485.0 			835.6 			394.2 			483.9 		
Industrial Revenues		128.0 			— 			604.3 			565.6 			385.2 			304.0 			333.7 		
Other Retail Revenues		29.4 			— 			77.4 			7.2 			12.9 			83.6 			8.6 		
Total Retail Revenues (a)		1,151.0 			— 			2,604.8 			1,787.8 			2,845.3 			1,440.8 			1,467.8 		
															
Wholesale Revenues:															
Generation Revenues (b)		— 			— 			250.4 			470.5 			— 			36.3 			216.8 		
	
Transmission Revenues (c)		313.4 			816.9 			82.7 			23.1 			58.5 			40.2 			108.4 		
	
Total Wholesale Revenues		313.4 			816.9 			333.1 			493.6 			58.5 			76.5 			325.2 		
															
Other Revenues from Contracts with Customers (d)		28.6 			15.1 			55.3 			99.6 			176.1 			19.1 			24.0 		

Total Revenues from Contracts with Customers		1,493.0 			832.0 			2,993.2 			2,381.0 			3,079.9 			1,536.4 			1,817.0 		
															
Other Revenues:															
Alternative Revenues (e)		(1.3)			(55.9)			(23.8)			(2.1)			(20.8)			10.9 			4.9 		
Other Revenues (e)		103.6 			— 			(1.9)			(8.2)			4.3 			— 			— 		
	
Total Other Revenues		102.3 			(55.9)			(25.7)			(10.3)			(16.5)			10.9 			4.9 		
															
Total Revenues		$	1,595.3 			$	776.1 			$	2,967.5 			$	2,370.7 			$	3,063.4 			$	1,547.3 			$	1,821.9 		

(a)2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $134 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $646 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $70 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(e)Amounts include affiliated and nonaffiliated revenues.

Performance Obligations

AEP has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same and have the same pattern of transfer to a customer. The invoice practical expedient within the accounting guidance for “Revenue from Contracts with Customers” allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer.

The purpose of the invoice practical expedient is to depict an entity’s measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. AEP subsidiaries elected to apply the invoice practical expedient to recognize revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for AEP’s subsidiaries are summarized as follows:

413

Retail Revenues

AEP’s subsidiaries within the Vertically Integrated Utilities and Transmission and Distribution Utilities segments have performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer’s usage requirements.

Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between AEP’s subsidiaries and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice. Payments from REPs are due to AEP Texas within 35 days.

Wholesale Revenues - Generation

AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments have performance obligations to sell electricity to wholesale customers from generation assets in PJM, SPP and ERCOT. The performance obligation to deliver electricity from generation assets is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Wholesale generation revenues are variable as they are subject to the customer’s usage requirements.

AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments also have performance obligations to stand ready in order to promote grid reliability. Stand ready services are sold into PJM’s RPM capacity market. RPM entails a base auction and at least three incremental auctions for a specific PJM delivery year, with the incremental auctions spanning three years. The performance obligation to stand ready is satisfied over time and the consideration for which is variable until the occurrence of the final incremental auction, at which point the performance obligation becomes fixed.

Payments from the RTO for stand ready services are typically received within one week from the issuance of the invoice, which is typically issued weekly. Gross margin resulting from generation sales within the Vertically Integrated Utilities segment are primarily subject to margin sharing agreements with customers and vary by state, where the revenues are reflected gross in the disaggregated revenues tables above.

APCo has a performance obligation to supply wholesale electricity to KGPCo through a PPA. The FERC regulates the cost-based wholesale power transactions between APCo and KGPCo. The purchased power agreement includes a component for the recovery of transmission costs under the FERC OATT. The transmission cost component of purchased power is cost-based and regulated by the Tennessee Regulatory Authority. APCo’s performance obligation under the purchased power agreement is satisfied over time as KGPCo simultaneously receives and consumes the wholesale electricity. APCo’s revenues from the purchased power agreement are presented within the Generation Revenues line in the disaggregated revenues tables above.

Wholesale Revenues - Transmission

AEP’s subsidiaries within the Vertically Integrated Utilities, Transmission and Distribution Utilities and AEP Transmission Holdco segments have performance obligations to transmit electricity to wholesale customers through assets owned and operated by AEP subsidiaries. The performance obligation to provide transmission services in PJM, SPP and ERCOT encompass a time frame greater than a year, where the performance obligation within each RTO is partially fixed for a period of one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for SPP and ERCOT and weekly for PJM.

414

AEP subsidiaries within the PJM and SPP regions collect revenues through transmission formula rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for the prior year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. The annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations,” and are therefore presented as such in the disaggregated revenues tables above. AEP subsidiaries within the ERCOT region collect revenues through a combination of base rates and interim Transmission Costs of Services filings that are approved by the PUCT.

The AEP East Companies are parties to the TA, which defines how transmission costs are allocated among the AEP East Companies on a 12-month average coincident peak basis. PSO, SWEPCo and AEPSC are parties to the TCA by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. AEPTCo is a transmission owner within the PJM and SPP regions providing transmission services to affiliates in accordance with the OATT, TA and TCA. Affiliate revenues as a result of the respective TA and the TCA are reflected as Transmission Revenues in the disaggregated revenues tables above.

Marketing, Competitive Retail and Renewable Revenues

AEP’s subsidiaries within the Generation & Marketing segment have performance obligations to deliver electricity to competitive retail and wholesale customers. Performance obligations for marketing, competitive retail and renewable offtake sales are satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are primarily variable as they are subject to customer’s usage requirements; however, certain contracts mandate a delivery of a set quantity of electricity at a predetermined price, resulting in a fixed performance obligation.

Payment terms under marketing arrangements typically follow standard Edison Electric Institute and International Swaps and Derivatives Association terms, which call for payment in 20 days. Payments for competitive retail and offtake arrangements for renewable assets range from 15 to 60 days and are dependent on the product sold, location and the creditworthiness of customer. Invoices for marketing arrangements, competitive retail and offtake arrangements for renewable assets are issued monthly.

Fixed Performance Obligations

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of December 31, 2020. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.

																																	
Company		2021		2022-2023		2024-2025		After 2025		Total	
		(in millions)	
AEP		$	1,122.9 			$	164.1 			$	162.2 			$	161.5 			$	1,610.7 		
AEP Texas		465.4 			— 			— 			— 			465.4 		
AEPTCo		1,319.5 			— 			— 			— 			1,319.5 		
APCo		173.4 			32.3 			23.2 			11.6 			240.5 		
I&M		35.1 			8.8 			8.8 			4.5 			57.2 		
OPCo		68.1 			— 			— 			0.1 			68.2 		
PSO		14.8 			— 			— 			— 			14.8 		
SWEPCo		41.6 			— 			— 			— 			41.6 		

415

Contract Assets and Liabilities

Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have any material contract assets as of December 31, 2020 and 2019.

When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheet in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have any material contract liabilities as of December 31, 2020 and 2019.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the Registrants’ balance sheets within the Accounts Receivable - Customers line item. The Registrants’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of December 31, 2020 and 2019. See “Securitized Accounts Receivable - AEP Credit” section of Note 14 for additional information.

The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets:

															
		Years Ended December 31,	
Company		2020		2019	
		(in millions)	
AEPTCo		$	81.0 			$	65.9 		
APCo		52.7 			47.3 		
I&M		34.8 			37.1 		
OPCo		45.9 			33.9 		
PSO		7.8 			9.7 		
SWEPCo		11.2 			17.6 		

Contract Costs

Contract costs to obtain or fulfill a contract for AEP subsidiaries within the Generation & Marketing segment are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and are neither bifurcated nor reclassified between current and noncurrent assets on the Registrants’ balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Other Operation on the Registrants’ income statements. The Registrants did not have material contract costs as of December 31, 2020 and 2019.
416

20.  GOODWILL

The disclosure in this note applies to AEP only.

The changes in AEP’s carrying amount of goodwill for the years ended December 31, 2020 and 2019 by operating segment are as follows:

		Corporate and Other		Generation
&
Marketing		AEP Consolidated	
	(in millions)	
Balance as of December 31, 2018		$	37.1 			$	15.4 			$	52.5 		
	
Impairment Losses		— 			— 			— 		
Balance as of December 31, 2019		37.1 			15.4 			52.5 		
Impairment Losses		— 			— 			— 		
Balance as of December 31, 2020		$	37.1 			$	15.4 			$	52.5 		

In the fourth quarters of 2020 and 2019, annual impairment tests were performed.  The fair values of the reporting units with goodwill were estimated using cash flow projections and other market value indicators.  There were no goodwill impairment losses.  AEP does not have any accumulated impairment on existing goodwill.

417

21.  SUBSEQUENT EVENTS

Impacts of Severe Winter Weather in February 2021

In February 2021, many of AEP’s service territories and customers were impacted by severe winter weather and extreme cold temperatures resulting in power outages, extensive damage to transmission and distribution infrastructure and disruption to the energy markets.

Storm Costs (Applies to AEP, APCo and SWEPCo)

Based on the information currently available, APCo, KPCo and SWEPCo currently estimate significant February 2021 storm restoration expenditures as shown in the table below. Management currently anticipates the storm restoration expenditures will be more heavily weighted towards other operation and maintenance expenses as compared to capital expenditures. Management will continue to refine these storm cost estimates as restoration efforts are completed and final costs become available.

		Total Estimated February 2021
Storm Restoration Expenditures	
		(in millions)	
APCo		$65.0	-	$75.0	
KPCo		$75.0	-	$95.0	
SWEPCo		$30.0	-	$40.0	

Management plans to seek regulatory recovery of these costs. If any of the storm 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, based on the information currently available, PSO’s and SWEPCo’s preliminary estimates of natural gas expenses and purchases of electricity are as follows:

		PSO		SWEPCo	
		(in millions)	
Estimated Natural Gas Expenses		$	175.0 			$	375.0 		
Estimated Electricity Purchases		650.0 			— 		
		$	825.0 			$	375.0 		

The amounts in the table above represent preliminary estimates as of February 25, 2021, and are subject to final settlement as additional information becomes available. In addition, SPP notified PSO and SWEPCo of additional collateral requirements of approximately $868 million on a cumulative basis for the companies due March 2, 2021. Subsequently, SPP filed a waiver request with the FERC that would grant a limited waiver for Load Serving Entities to post this additional collateral requirement between February 24, 2021 and March 11, 2021. FERC approved the waiver request on February 24, 2021.

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 regulators to perform a heightened review of the costs. Management believes these costs are probable of future recovery. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. Nevertheless, PSO and SWEPCo’s payments to suppliers are due in March 2021.
418

PSO and SWEPCo are evaluating financing alternatives including funding contributions from Parent and long-term debt issuances to address the timing difference between the payment to suppliers and recovery from customers. If either PSO or SWEPCo is unable to recover these fuel and purchased power expenses or recover these expenses in a timely manner, it could reduce future net income and cash flows and impact financial condition.

ERCOT (Applies to AEP and AEP Texas)

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. While recovery from the emergency conditions is continuing, some market conditions and activities have yet to return to normal. 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.
419

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Information required by this item is set forth under the caption Proposal to Ratify the Appointment of the Independent Registered Public Accounting Firm in the 2021 Proxy Statement, which is incorporated by reference into this item.

ITEM 9A.   CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

During 2020, management, including the principal executive officer and principal financial officer of each of the Registrants evaluated each respective Registrant’s disclosure controls and procedures.  Disclosure controls and procedures are defined as controls and other procedures of the Registrant that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to each Registrant’s management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of December 31, 2020, the principal executive officer and financial officer of each of the Registrants concluded that the disclosure controls and procedures in place were effective at the reasonable assurance level.  The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

Changes in Internal Control over Financial Reporting

There have been no changes in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter 2020 that materially affected, or are reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

Internal Control over Financial Reporting

See Management’s Report on Internal Control over Financial Reporting for each Registrant under Item 8. As discussed in that report, management assessed and reported on the effectiveness of each Registrant’s internal control over financial reporting as of December 31, 2020.  As a result of that assessment, management concluded that each Registrant’s internal control over financial reporting was effective as of December 31, 2020.

ITEM 9B.   OTHER INFORMATION

None.

420

PART III

ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

AEP

Directors, Director Nomination Process and Audit Committee

Certain of the information called for in this Item 10, including the information relating to directors, is incorporated herein by reference to AEP’s definitive proxy information statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2021 Annual Meeting of Shareholders (the 2021 Annual Meeting) including under the captions “Election of Directors,” “AEP’s Board of Directors and Committees,” “Directors” and “Nominees for Directors.”

Executive Officers

Reference also is made under the caption “Information About our Executive Officers” in Part I, Item 1 of this report.

Code of Ethics

AEP’s Principles of Business Conduct is the code of ethics that applies to AEP’s Chief Executive Officer, Chief Financial Officer and principal accounting officer.  The Principles of Business Conduct is available on AEP’s website at www.aep.com.  The Principles of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Investor Relations, American Electric Power Company, Inc., 1 Riverside Plaza, Columbus, Ohio 43215.

If any substantive amendments to the Principles of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Principles of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or principal accounting officer, AEP will disclose the nature of such amendment or waiver on AEP’s website, www.aep.com, or in a report on Form 8-K.

Delinquent Section 16(a) Reports

None.

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

ITEM 11.   EXECUTIVE COMPENSATION

AEP

The information called for by this Item 11 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2021 Annual Meeting including under the captions “Compensation Discussion and Analysis,” “Executive Compensation”, “Director Compensation” and “2020 Director Compensation Table”.  The information set forth under the subcaption “Human Resources Committee Report” and “Audit Committee Report” should not be deemed filed nor should it be incorporated by reference into any other filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent AEP specifically incorporates such report by reference therein.

421

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

AEP

The information relating to Security Ownership of Certain Beneficial Owners is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 2021 Annual Meeting under the caption “Share Ownership of Certain Beneficial Owners and Management” and “Share Ownership of Directors and Executive Officers.”

EQUITY COMPENSATION PLAN INFORMATION

The following table summarizes the ability of AEP to issue common stock pursuant to equity compensation plans as of December 31, 2020:
																					
Plan Category		Number of Securities to be Issued upon Exercise of Outstanding Options Warrants and Rights (a)		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Securities Remaining
Available for Future Issuance under Equity Compensation Plans	
Equity Compensation Plans Approved by Security Holders		2,744,760		—		6,712,148	
Equity Compensation Plans Not Approved by Security Holders		—		—		—	
Total		2,744,760		—		6,712,148	

(a)The balance includes unvested 2020 performance units and restricted stock units as well as vested performance units deferred as AEP career shares, all of which will be settled and paid in shares of AEP common stock. Performance units, restricted stock units and AEP career shares that are settled and paid in cash are not included. For performance units, the total includes the target number of shares that could be granted if performance meets target objectives. The number of securities that would be granted, with respect to performance units, if performance meets the maximum payout level, is two times the amount included in this total.
(b)No consideration is required from participants for the exercise or vesting of any outstanding AEP equity compensation awards.

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

AEP

The information called for by this Item 13 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2021 Annual Meeting under the captions “Transactions with Related Persons” and “Director Independence.”
422

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

ITEM 14.   PRINCIPAL ACCOUNTING FEES AND SERVICES

AEP

The information called for by this Item 14 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2021 Annual Meeting under the captions “Audit and Non-Audit Fees,” “Audit Committee Report” and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor.”

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Each of the above is a wholly-owned subsidiary of AEP and does not have a separate audit committee. A description of the AEP Audit Committee pre-approval policies, which apply to these companies, is contained in the definitive proxy statement of AEP for the 2021 Annual Meeting of shareholders. The following table presents directly billed fees for professional services rendered by PricewaterhouseCoopers LLP for the audit of these companies’ annual financial statements for the years ended December 31, 2020 and 2019, and fees directly billed for other services rendered by PricewaterhouseCoopers LLP during those periods. PricewaterhouseCoopers LLP also provides additional professional and other services to the AEP System, the cost of which may ultimately be allocated to these companies though not billed directly to them. For a description of these fees and services, see the description of principal accounting fees and services for AEP above.

 	AEP Texas		AEPTCo		APCo	
 	2020		2019		2020		2019		2020		2019	
Audit Fees	$	1,204,518 			$	1,383,288 			$	1,249,959 			$	1,282,508 			$	1,747,977 			$	1,684,045 		
Audit-Related Fees	80,000 			132,667 			— 			— 			44,857 			70,904 		
Tax Fees	6,349 			27,092 			6,433 			31,009 			9,090 			39,326 		
	
Total	$	1,290,867 			$	1,543,047 			$	1,256,392 			$	1,313,517 			$	1,801,924 			$	1,794,275 		

																																				
 	I&M		OPCo		PSO	
 	2020		2019		2020		2019		2020		2019	
Audit Fees	$	1,383,356 			$	1,336,192 			$	1,096,241 			$	1,056,377 			$	577,138 			$	575,734 		
Audit-Related Fees	10,607 			10,071 			10,607 			10,071 			4,857 			4,571 		
Tax Fees	8,169 			35,073 			5,701 			26,384 			3,281 			15,093 		
	
Total	$	1,402,132 			$	1,381,336 			$	1,112,549 			$	1,092,832 			$	585,276 			$	595,398 		

												
 	SWEPCo	
 	2020		2019	
Audit Fees	$	951,594 			$	973,150 		
Audit-Related Fees	25,857 			24,571 		
Tax Fees	5,523 			23,263 		
	
Total	$	982,974 			$	1,020,984 		

423

PART IV

ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as a part of this report:

1.FINANCIAL STATEMENTS:

The following financial statements have been incorporated herein by reference pursuant to Item 8.

AEP and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2020, 2019 and 2018; Consolidated Statements of Changes in Equity for the years ended December 31, 2020, 2019 and 2018; Consolidated Balance Sheets as of December 31, 2020 and 2019; Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018; Notes to Financial Statements of Registrants.

AEP Texas, APCo, I&M and OPCo:
Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2020, 2019 and 2018; Consolidated Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2020, 2019 and 2018; Consolidated Balance Sheets as of December 31, 2020 and 2019; Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018; Notes to Financial Statements of Registrants.

AEPTCo:
Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018; Consolidated Statements of Changes in Member’s Equity for the years ended December 31, 2020, 2019 and 2018; Consolidated Balance Sheets as of December 31, 2020 and 2019; Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018; Notes to Financial Statements of Registrants.

PSO:
Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Statements of Income for the years ended December 31, 2020, 2019 and 2018; Statements of Comprehensive Income (Loss) for the years ended December 31, 2020, 2019 and 2018; Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2020, 2019 and 2018; Balance Sheets as of December 31, 2020 and 2019; Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018; Notes to Financial Statements of Registrants.

SWEPCo:
Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2020, 2019 and 2018; Consolidated Statements of Changes in Equity for the years ended December 31, 2020, 2019 and 2018; Consolidated Balance Sheets as of December 31, 2020 and 2019; Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018; Notes to Financial Statements of Registrants.
424

									
2.  FINANCIAL STATEMENT SCHEDULES:		Page Number	
Financial Statement Schedules are listed in the Index of Financial Statement Schedules.  (Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable). Reports of Independent Registered Public Accounting Firm.		S-1	
 		 	
3.  EXHIBITS:			
Exhibits for AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.		E-1	

ITEM 16.   FORM 10-K SUMMARY

None.

425

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 	American Electric Power Company, Inc.	
 	 	 	
 	By:	/s/   Julia A. Sloat	
 	 	(Julia A. Sloat, Executive Vice President	
 	 	and Chief Financial Officer)	
Date: February 25, 2021

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	 	Title	 	Date	
 		 	 	 	 	
(i)	Principal Executive Officer:	 	 	 	 	
 		 	 	 	 	
	 /s/   Nicholas K. Akins	 	Chairman of the Board,
Chief Executive Officer and Director	 	February 25, 2021	
	(Nicholas K. Akins)	 		 	 	
 		 	 	 	 	
(ii)	Principal Financial Officer:	 	 	 	 	
 		 	 	 	 	
	/s/   Julia A. Sloat	 	Executive Vice President and Chief Financial Officer	 	February 25, 2021	
	(Julia A. Sloat)	 		 	 	
 		 	 	 	 	
(iii)	Principal Accounting Officer:	 	 	 	 	
 		 	 	 	 	
	/s/   Joseph M. Buonaiuto	 	Senior Vice President, Controller and Chief Accounting Officer	 	February 25, 2021	
	(Joseph M. Buonaiuto)	 		 	 	
 		 	 	 	 	
(iv)           	A Majority of the Directors:	 	 	 	 	
 		 	 	 	 	
	*Nicholas K. Akins	 	 	 	 	
	*David J. Anderson	 	 	 	 	
	*J. Barnie Beasley, Jr.	 	 	 	 	
	*Ralph D. Crosby, Jr.	 	 	 	 	
	*Art A. Garcia					
	*Linda A. Goodspeed	 	 	 	 	
	*Thomas E. Hoaglin	 	 	 	 	
	*Sandra Beach Lin	 	 	 	 	
	*Margaret M. McCarthy					
	*Richard C. Notebaert	 	 	 	 	
	*Stephen S. Rasmussen					
	*Oliver G. Richard, III					
	*Daryl Roberts					
	*Sara Martinez Tucker	 	 	 	 	
 		 	 	 	 	
*By: 	/s/   Julia A. Sloat	 	 	 	February 25, 2021	
 	(Julia A. Sloat, Attorney-in-Fact	 	 	 	 	
426

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

	AEP Texas Inc.	
 	Appalachian Power Company	
 	Ohio Power Company	
 	Public Service Company of Oklahoma	
 	Southwestern Electric Power Company	
 	 	 	
 	By:	/s/   Julia A. Sloat	
 	 	(Julia A. Sloat, Vice President and Chief Financial Officer	
Date: February 25, 2021

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	 	Title	 	Date	
 		 	 	 	 	
(i)	Principal Executive Officer:	 	 	 	 	
 		 	 	 	 	
	/s/   Nicholas K. Akins	 	Chairman of the Board, Chief Executive Officer and Director	 	February 25, 2021	
	(Nicholas K. Akins)	 		 	 	
 		 	 	 	 	
(ii)	Principal Financial Officer:	 	 	 	 	
 		 	 	 	 	
	/s/   Julia A. Sloat	 	Vice President, Chief Financial Officer and Director	 	February 25, 2021	
	(Julia A. Sloat)	 		 	 	
 		 	 	 	 	
(iii) 	Principal Accounting Officer:	 	 	 	 	
 		 	 	 	 	
	/s/   Joseph M. Buonaiuto	 	Controller and Chief Accounting Officer	 	February 25, 2021	
	(Joseph M. Buonaiuto)	 		 	 	
 		 	 	 	 	
(iv)	A Majority of the Directors:	 	 	 	 	
 		 	 	 	 	
	*Nicholas K. Akins	 	 	 	 	
	*Lisa M. Barton	 	 	 	 	
	*Paul Chodak III					
	*David M. Feinberg	 	 	 	 	
	*Mark C. McCullough					
	*Charles R. Patton	 	 	 	 	
	Julia A. Sloat					
	*Brian X. Tierney					
 		 	 	 	 	
*By:	/s/   Julia A. Sloat	 	 	 	February 25, 2021	
	(Julia A. Sloat, Attorney-in-Fact)	 	 	 	 	
427

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 	Indiana Michigan Power Company	
 	 	 	
 	By:	/s/ Julia A. Sloat	
 	 	(Julia A. Sloat, Vice President,	
 	 	and Chief Financial Officer)	
Date: February 25, 2021

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	 	Title	 	Date	
 		 	 	 	 	
(i)	Principal Executive Officer:	 	 	 	 	
 		 	 	 	 	
	/s/   Nicholas K. Akins	 	Chairman of the Board, Chief Executive Officer and Director	 	February 25, 2021	
	(Nicholas K. Akins)	 		 	 	
 		 	 	 	 	
(ii)	Principal Financial Officer:	 	 	 	 	
 		 	 	 	 	
	/s/   Julia A. Sloat	 	Vice President, Chief Financial Officer and Director	 	February 25, 2021	
	(Julia A. Sloat)	 		 	 	
 		 	 	 	 	
(iii)	Principal Accounting Officer:	 	 	 	 	
 		 	 	 	 	
	/s/   Joseph M. Buonaiuto	 	Controller and Chief Accounting Officer	 	February 25, 2021	
	(Joseph M. Buonaiuto)	 		 	 	
 		 	 	 	 	
(iv)	A Majority of the Directors:	 	 	 	 	
 		 	 	 	 	
	*Nicholas K. Akins	 	 	 	 	
	*Lisa M. Barton	 	 	 	 	
	*Nicholas M. Elkins					
	*David M. Feinberg	 	 	 	 	
	*David S. Isaacson					
	*Marc E. Lewis	 	 	 	 	
	*David A. Lucas	 		 	 	
	*Mark C. McCullough	 	 	 	 	
	Julia A. Sloat	 	 	 	 	
	*Toby L. Thomas					
	*Brian X. Tierney					
						
*By:	/s/   Julia A. Sloat	 	 	 	February 25, 2021	
	(Julia A. Sloat, Attorney-in-Fact)	 	 	 	 	
428

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 	AEP Transmission Company, LLC	
 	 	 	
 	By:	/s/   Julia A. Sloat	
 	 	(Julia A. Sloat, Vice President	
 	 	and Chief Financial Officer)	
Date: February 25, 2021

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature	 	Title	 	Date	
 		 	 	 	 	
(i)	Principal Executive Officer:	 	 	 	 	
 		 	 	 	 	
	/s/   Nicholas K. Akins	 	Chairman of the Board, Chief Executive Officer and Manager	 	February 25, 2021	
	(Nicholas K. Akins)	 		 	 	
 		 	 	 	 	
(ii)	Principal Financial Officer:	 	 	 	 	
 		 	 	 	 	
	/s/   Julia A. Sloat	 	Vice President, Chief Financial Officer and Manager	 	February 25, 2021	
	(Julia A. Sloat)	 		 	 	
 		 	 	 	 	
(iii)	Principal Accounting Officer:	 	 	 	 	
 		 	 	 	 	
	/s/   Joseph M. Buonaiuto	 	Controller and Chief Accounting Officer	 	February 25, 2021	
	(Joseph M. Buonaiuto)	 		 	 	
 		 	 	 	 	
(iv)	A Majority of the Managers:	 	 	 	 	
 		 	 	 	 	
	*Nicholas K. Akins	 	 	 	 	
	*David M. Feinberg	 	 	 	 	
	*Mark C. McCullough	 	 	 	 	
	Julia A. Sloat					
	*A. Wade Smith					
						
*By:	/s/   Julia A. Sloat	 	 	 	February 25, 2021	
	(Julia A. Sloat, Attorney-in-Fact)	 	 	 	 	
429

INDEX OF FINANCIAL STATEMENT SCHEDULES

	Page
Number	
Reports of Independent Registered Public Accounting Firm	S-2	
 		
The following financial statement schedules are included in this report on the pages indicated:		
 		
American Electric Power Company, Inc. (Parent):		
Schedule I – Condensed Financial Information	S-3	
Schedule I – Index of Condensed Notes to Condensed Financial Information	S-7	
 		
American Electric Power Company, Inc. and Subsidiary Companies:		
Schedule II – Valuation and Qualifying Accounts and Reserves	S-11	

S-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
FINANCIAL STATEMENT SCHEDULES

To the Board of Directors and Shareholders of
American Electric Power Company, Inc.

Our audits of the consolidated financial statements referred to in our report dated February 25, 2021 appearing in the 2020 Annual Report to Shareholders of American Electric Power Company, Inc (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the accompanying schedule of condensed financial information as of December 31, 2020 and 2019 and for each of the three years in the period ended December 31, 2020 and schedule of valuation and qualifying accounts and reserves for each of the three years in the period ended December 31, 2020. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021
S-2

SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2020, 2019 and 2018
(in millions, except per-share and share amounts)

 		Years Ended December 31,	
 		2020		2019		2018	
REVENUES		 		 		 	
Affiliated Revenues		$	14.1 			$	11.0 			$	9.5 		
Other Revenues		1.1 			1.3 			1.4 		
MTM – Interest Rate Hedge		(5.4)			(0.5)			— 		
TOTAL REVENUES		9.8 			11.8 			10.9 		
							
EXPENSES		 		 		 	
Other Operation		21.4 			53.2 			39.7 		
	
Asset Impairments and Other Related Charges		— 			— 			9.3 		
Depreciation and Amortization		0.3 			0.2 			0.3 		
	
TOTAL EXPENSES		21.7 			53.4 			49.3 		
							
OPERATING LOSS		(11.9)			(41.6)			(38.4)		
							
Other Income (Expense):		 		 		 	
	
Interest Income		39.2 			53.5 			31.3 		
Interest Expense		(178.5)			(159.2)			(87.5)		
							
LOSS BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS		(151.2)			(147.3)			(94.6)		
							
Income Tax Expense (Benefit)		(0.6)			22.8 			(6.2)		
Equity Earnings of Unconsolidated Subsidiaries		2,350.7 			2,091.2 			2,012.2 		

	

NET INCOME		2,200.1 			1,921.1 			1,923.8 		
							
Other Comprehensive Income (Loss)		62.6 			(27.3)			(23.7)		
							
TOTAL COMPREHENSIVE INCOME		$	2,262.7 			$	1,893.8 			$	1,900.1 		
							
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING		495,718,223 			493,694,345 			492,774,600 		

	
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	4.44 			$	3.89 			$	3.90 		
							
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING		497,226,867 			495,306,238 			493,758,277 		

	
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	4.42 			$	3.88 			$	3.90 		
							
See Condensed Notes to Condensed Financial Information beginning on page S-7.							
S-3

SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS
ASSETS
December 31, 2020 and 2019
(in millions)

 		December 31,	
 		2020		2019	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	299.7 			$	156.1 		
Other Temporary Investments		2.4 			2.0 		
Advances to Affiliates		3,163.7 			2,197.9 		
Accounts Receivable:					
Affiliated Companies		35.8 			11.3 		
General		0.3 			0.3 		
	
Total Accounts Receivable		36.1 			11.6 		
Affiliated Notes Receivable		— 			20.0 		
Accrued Tax Benefits		27.1 			7.1 		
Prepayments and Other Current Assets		4.6 			9.9 		
TOTAL CURRENT ASSETS		3,533.6 			2,404.6 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
General		2.0 			2.3 		
Construction Work in Progress		— 			0.2 		
Total Property, Plant and Equipment		2.0 			2.5 		
Accumulated Depreciation, Depletion and Amortization		1.0 			1.4 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		1.0 			1.1 		
					
OTHER NONCURRENT ASSETS		 		 	
Investments in Unconsolidated Subsidiaries		25,764.2 			23,329.9 		
	
Affiliated Notes Receivable		65.0 			39.0 		
Deferred Charges and Other Noncurrent Assets		79.2 			95.7 		
TOTAL OTHER NONCURRENT ASSETS		25,908.4 			23,464.6 		
					
TOTAL ASSETS		$	29,443.0 			$	25,870.3 		
					
See Condensed Notes to Condensed Financial Information beginning on page S-7.	
S-4

SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2020 and 2019
(dollars in millions)

		December 31,	
 		2020		2019	
CURRENT LIABILITIES		 			
Advances from Affiliates		$	447.2 			$	252.6 		
Accounts Payable:					
General		3.0 			0.5 		
Affiliated Companies		8.0 			8.4 		
Short-term Debt		1,852.3 			2,110.0 		
Long-term Debt Due Within One Year – Nonaffiliated (a)		410.4 			501.9 		
Accrued Taxes		3.8 			44.2 		
Other Current Liabilities		87.4 			38.1 		
TOTAL CURRENT LIABILITIES		2,812.1 			2,955.7 		
					
NONCURRENT LIABILITIES		 		 	
Long-term Debt – Nonaffiliated (a)		5,873.2 			3,122.9 		
Deferred Credits and Other Noncurrent Liabilities		161.6 			116.6 		
TOTAL NONCURRENT LIABILITIES		6,034.8 			3,239.5 		
					
TOTAL LIABILITIES		8,846.9 			6,195.2 		
					
MEZZANINE EQUITY					
Contingently Redeemable Performance Share Awards		45.2 			42.9 		
					
COMMON SHAREHOLDERS’ EQUITY		 		 	
Common Stock – Par Value – $6.50 Per Share:		 		 	
 	2020		2019			 		 	
Shares Authorized	600,000,000		600,000,000			 		 	
Shares Issued	516,808,354		514,373,631			 		 	
(20,204,160 Shares were Held in Treasury as of December 31, 2020 and 2019, Respectively)		3,359.3 			3,343.4 		
Paid-in Capital		6,588.9 			6,535.6 		
Retained Earnings		10,687.8 			9,900.9 		
Accumulated Other Comprehensive Income (Loss)		(85.1)			(147.7)		
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY		20,550.9 			19,632.2 		
					
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY		$	29,443.0 			$	25,870.3 		

						
(a)	Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 included in the 2020 Annual Reports for additional information.	
		
See Condensed Notes to Condensed Financial Information beginning on page S-7.	
S-5

SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

 		Years Ended December 31,	
 		2020		2019		2018	
OPERATING ACTIVITIES		 		 		 	
Net Income		$	2,200.1 			$	1,921.1 			$	1,923.8 		

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:							
Depreciation and Amortization		0.3 			0.2 			0.3 		
Deferred Income Taxes		8.2 			26.5 			(45.0)		
Asset Impairments and Other Related Charges		— 			— 			9.3 		
Interest Rate Hedge Settlement		57.5 			— 			— 		
Equity Earnings of Unconsolidated Subsidiaries		(2,350.7)			(2,091.2)			(2,012.2)		
Cash Dividends Received from Unconsolidated Subsidiaries		454.0 			426.2 			855.6 		
Change in Other Noncurrent Assets		1.1 			0.1 			(5.5)		
Change in Other Noncurrent Liabilities		39.2 			84.5 			42.1 		
Changes in Certain Components of Working Capital:							
Accounts Receivable, Net		(24.5)			2.4 			(3.9)		
Accounts Payable		2.1 			(1.2)			— 		

Other Current Assets		1.3 			(0.8)			47.8 		
Other Current Liabilities		(55.8)			36.4 			4.7 		
Net Cash Flows from Operating Activities		332.8 			404.2 			817.0 		
							
INVESTING ACTIVITIES		 		 		 	

Construction Expenditures		(0.2)			(0.3)			(0.4)		
	
Change in Advances to Affiliates, Net		(965.8)			(1,101.5)			(106.9)		
Capital Contributions to Unconsolidated Subsidiaries		(436.5)			(212.8)			(859.1)		
Repayment of Notes Receivable from Unconsolidated Subsidiaries		20.0 			70.9 			199.7 		
Issuance of Notes Receivable to Unconsolidated Subsidiaries		(26.0)			(9.0)			— 		
Other Investing Activities		2.7 			— 			— 		
Net Cash Flows Used for Investing Activities		(1,405.8)			(1,252.7)			(766.7)		
							
FINANCING ACTIVITIES		 		 		 	
Issuance of Common Stock, Net		155.0 			65.3 			73.6 		
Issuance of Long-term Debt		3,113.9 			1,321.3 			991.9 		
Issuance of Short-term Debt with Original Maturities Greater Than 90 Days		1,396.5 			— 			205.6 		
Change in Short-term Debt with Original Maturities Less Than 90 Day, Net		(347.1)			950.0 			261.4 		
Retirement of Long-term Debt		(500.0)			— 			— 		
Change in Advances from Affiliates, Net		194.6 			(61.0)			(151.5)		
Redemption of Short-term Debt with Original Maturities Greater Than 90 Days		(1,307.1)			— 			(205.6)		
	
Dividends Paid on Common Stock		(1,415.0)			(1,345.5)			(1,251.1)		
Other Financing Activities		(74.2)			(24.8)			(7.4)		
Net Cash Flows from (Used for) Financing Activities		1,216.6 			905.3 			(83.1)		

	

Net Increase (Decrease) in Cash and Cash Equivalents		143.6 			56.8 			(32.8)		
Cash and Cash Equivalents at Beginning of Period		156.1 			99.3 			132.1 		
Cash and Cash Equivalents at End of Period		$	299.7 			$	156.1 			$	99.3 		
							
See Condensed Notes to Condensed Financial Information beginning on page S-7.	
S-6

SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL INFORMATION

1.   Summary of Significant Accounting Policies	
 	
2.   Commitments, Guarantees and Contingencies	
 	
3.   Financing Activities	
 	
4.   Related Party Transactions	

S-7

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The condensed financial information of Parent is required as a result of the restricted net assets of AEP consolidated subsidiaries exceeding 25% of AEP consolidated net assets as of December 31, 2020.  Parent is a public utility holding company that owns all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries, including joint ventures and equity investments.  The primary source of income for Parent is equity in its subsidiaries’ earnings.  Its major source of cash is dividends from the subsidiaries.  Parent borrows the funds for the money pool that is used by the subsidiaries for their short-term cash needs. Parent financial statements should be read in conjunction with the AEP consolidated financial statements and the accompanying notes thereto. For purposes of these condensed financial statements, AEP wholly-owned and majority-owned subsidiaries are recorded based upon its proportionate share of the subsidiaries’ net assets (similar to presenting them on the equity method).

Income Taxes

Parent files a consolidated federal income tax return with its subsidiaries. The tax benefit of Parent is allocated to its subsidiaries with taxable income reducing their current tax expense proportionately. With the exception of the allocation of the consolidated AEP System NOL, the loss of parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.

2.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

Parent and its subsidiaries are parties to environmental and other legal matters. Parent has issued guarantees over the performance of certain equity method investees.

Guarantees of Equity Method Investees (Applies to AEP)

In April 2019, AEP acquired Sempra Renewables LLC. The transaction resulted in the acquisition of 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 December 31, 2020, 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 $31 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 liability is based upon assessments of the credit quality and default probabilities of the respective PPA counterparties.

For further discussion, see Note 6 - Commitments, Guarantees and Contingencies included in the 2020 Annual Report.

S-8

3.  FINANCING ACTIVITIES

The following details long-term debt outstanding as of December 31, 2020 and 2019:

Long-term Debt

 				Weighted-Average		Interest Rate Ranges as of		Outstanding as of	
				Interest Rate as of		December 31,		December 31,	
Type of Debt		Maturity		December 31, 2020		2020		2019		2020		2019	
 				 		 		 		(in millions)	
Senior Unsecured Notes		2020-2050		2.44%		0.70%-4.30%		2.15%-4.30%		$	4,123.6 			$	2,301.5 		
Pollution Control Bonds		2024-2029 (a)		2.26%		1.90%-2.60%		1.90%-2.60%		535.9 			535.5 		
Junior Subordinate Notes		2022-2023		2.32%		1.30%-3.40%		3.40%		1,624.1 			787.8 		
Total Long-term Debt Outstanding				 		 		 		6,283.6 			3,624.8 		
Long-term Debt Due Within One Year										410.4 			501.9 		
Long-term Debt										$	5,873.2 			$	3,122.9 		

(a)Certain Pollution Control Bonds are subject to redemption earlier than the maturity date.

Long-term debt outstanding as of December 31, 2020 is payable as follows:

	2021		2022		2023		2024		2025		After 2025		Total	
 	(in millions)	
Principal Amount (a)	$	410.4 			$	1,115.7 			$	1,909.6 			$	306.5 			$	454.9 			$	2,148.6 			$	6,345.7 		
Unamortized Discount, Net and Debt Issuance Costs	 		 		 		 		 		 		(62.1)		
Total Long-term Debt Outstanding	 		 		 		 		 		 		$	6,283.6 		

(a)Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 included in the 2020 Annual Report for additional information.

Short-term Debt

Parent’s outstanding short-term debt was as follows:

 		December 31, 2020		December 31, 2019	
Type of Debt		Outstanding
Amount		Weighted-Average
Interest Rate		Outstanding
Amount		Weighted-Average
Interest Rate	
 		(in millions)		 		(in millions)		 	
Commercial Paper		$	1,852.3 			0.29 	%		$	2,110.0 			2.10 	%	
Total Short-term Debt		$	1,852.3 			 		$	2,110.0 			 	

4.  RELATED PARTY TRANSACTIONS

Payments on Behalf of Subsidiaries

Due to occasional time sensitivity and complexity of payments, Parent makes certain insurance, tax and benefit payments on behalf of subsidiary companies.  Parent is then fully reimbursed by the subsidiary companies.

S-9

Short-term Lending to Subsidiaries

Parent uses a commercial paper program to meet the short-term borrowing needs of subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  The program also allows some direct borrowers to invest excess cash with Parent.

Interest expense related to Parent’s short-term borrowing is included in Interest Expense on Parent’s statements of income.  Parent incurred interest expense for amounts borrowed from subsidiaries of $4 million, $8 million and $11 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Interest income related to Parent’s short-term lending is included in Interest Income on Parent’s statements of income.  Parent earned interest income for amounts advanced to subsidiaries of $36 million, $49 million and $27 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Affiliated Notes

Parent issued long-term debt, portions of which were loaned to its subsidiaries.  Parent pays interest on the affiliated notes, but the subsidiaries accrue interest for their share of the affiliated borrowing and remit the interest to Parent.  Interest income related to Parent’s loans to subsidiaries is included in Interest Income on Parent’s statements of income.  Parent earned interest income on loans to subsidiaries of $2 million, $2 million and $2 million for the years ended December 31, 2020, 2019 and 2018, respectively.
S-10

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

																																	
AEP		 		Additions		 		 	
Description		Balance at
Beginning
of Period		Charged to
Costs and
Expenses		Charged to Other
Accounts (a)		Deductions (b)		Balance at
End of
Period	
 		(in millions)	
Deducted from Assets:		 		 		 		 		 	
Accumulated Provision for Uncollectible Accounts:		 		 		 		 		 	
Year Ended December 31, 2020		$	43.7 			$	46.0 			$	5.9 			$	24.5 			$	71.1 		
Year Ended December 31, 2019		36.8 			41.3 			3.6 			38.0 			43.7 		
Year Ended December 31, 2018		38.5 			37.3 			2.6 			41.6 			36.8 		

(a)Recoveries offset by reclasses to other assets and liabilities.
(b)Uncollectible accounts written off.

Schedule II for the Registrant Subsidiaries is not presented because the amounts are not material.
S-11

INDEX OF AEP TRANSMISSION COMPANY, LLC (AEPTCO PARENT)
FINANCIAL STATEMENT SCHEDULES

	Page
Number	
Report of Independent Registered Public Accounting Firm on Financial Statement Schedule	S-13	
 		
The following financial statement schedules are included in this report on the pages indicated:		
 		
AEP Transmission Company, LLC (AEPTCo Parent):		
Schedule I – Condensed Financial Information	S-14	
Schedule I – Index of Condensed Notes to Condensed Financial Information	S-18	
S-12

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
FINANCIAL STATEMENT SCHEDULE

To the Board of Directors and Member of
AEP Transmission Company, LLC

Our audits of the consolidated financial statements referred to in our report dated February 25, 2021 appearing in the 2020 Annual Report to Shareholders of AEP Transmission Company, LLC (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the accompanying schedule of condensed financial information as of December 31, 2020 and 2019 and for each of the three years in the period ended December 31, 2020. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021
S-13

SCHEDULE I
AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

 		Years Ended December 31,	
 		2020		2019		2018	
EXPENSES		 		 		 	
Other Operation		$	0.2 			$	0.3 			$	— 		
	
TOTAL EXPENSES		0.2 			0.3 			— 		
							
OPERATING LOSS		(0.2)			(0.3)			— 		
							
Other Income (Expense):		 		 		 	
	
Interest Income - Affiliated		149.6 			123.8 			104.6 		
Interest Expense		(148.1)			(122.1)			(103.4)		
							
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS OF UNCONSOLIDATED SUBSIDIARIES		1.3 			1.4 			1.2 		
							
Income Tax Expense		0.2 			0.3 			0.2 		
Equity Earnings of Unconsolidated Subsidiaries		422.3 			438.6 			314.9 		
							
NET INCOME		$	423.4 			$	439.7 			$	315.9 		
							
See Condensed Notes to Condensed Financial Information beginning on page S-18.	
S-14

SCHEDULE I
AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS
ASSETS
December 31, 2020 and 2019
(in millions)

 		December 31,	
 		2020		2019	
CURRENT ASSETS		 		 	

Advances to Affiliates		$	109.0 			$	68.7 		
Accounts Receivable:		 		 	
	
Affiliated Companies		26.5 			23.1 		
	
Total Accounts Receivable		26.5 			23.1 		

Notes Receivable - Affiliated		50.0 			— 		
TOTAL CURRENT ASSETS		185.5 			91.8 		

	

	

	
OTHER NONCURRENT ASSETS		 		 	
Notes Receivable - Affiliated		3,898.5 			3,427.3 		
	
Investments in Unconsolidated Subsidiaries		4,712.0 			4,009.7 		
	
TOTAL OTHER NONCURRENT ASSETS		8,610.5 			7,437.0 		
					
TOTAL ASSETS		$	8,796.0 			$	7,528.8 		
					
See Condensed Notes to Condensed Financial Information beginning on page S-18.	
S-15

SCHEDULE I
AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2020 and 2019
(in millions)

		December 31,	
 		2020		2019	
CURRENT LIABILITIES		 			
	
Accounts Payable:		 		 	
General		$	62.2 			$	35.6 		
Affiliated Companies		41.0 			35.0 		
	
Long-term Debt Due Within One Year – Nonaffiliated		50.0 			— 		
	
Accrued Interest		23.9 			19.2 		
	
Other Current Liabilities		7.5 			2.2 		
TOTAL CURRENT LIABILITIES		184.6 			92.0 		
					
NONCURRENT LIABILITIES		 		 	
Long-term Debt – Nonaffiliated		3,898.5 			3,427.3 		

	
	
TOTAL NONCURRENT LIABILITIES		3,898.5 			3,427.3 		
					
TOTAL LIABILITIES		4,083.1 			3,519.3 		
					
MEMBER’S EQUITY		 		 	
Paid-in Capital		2,765.6 			2,480.6 		
Retained Earnings		1,947.3 			1,528.9 		
TOTAL MEMBER’S EQUITY		4,712.9 			4,009.5 		
					
TOTAL LIABILITIES AND MEMBER’S EQUITY		$	8,796.0 			$	7,528.8 		
									
See Condensed Notes to Condensed Financial Information beginning on page S-18.	
S-16

SCHEDULE I
AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2020, 2019 and 2018
(in millions)

 		Years Ended December 31,	
 		2020		2019		2018	
OPERATING ACTIVITIES		 		 		 	
Net Income		$	423.4 			$	439.7 			$	315.9 		
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:		 		 		 	

	

Equity Earnings of Unconsolidated Subsidiaries		(422.3)			(438.6)			(314.9)		
	
Change in Other Noncurrent Liabilities		5.6 			11.9 			— 		
Changes in Certain Components of Working Capital:		 		 		 	
Accounts Receivable, Net		(3.4)			(6.0)			0.2 		
	
Accounts Payable		5.3 			18.8 			(6.4)		
	
Accrued Interest		4.7 			3.3 			0.9 		
	
Other Current Liabilities		32.5 			34.6 			(1.2)		
Net Cash Flows from (Used for) Operating Activities		45.8 			63.7 			(5.5)		
							
INVESTING ACTIVITIES		 		 		 	

	
	
Change in Advances to Affiliates, Net		(40.3)			(51.7)			5.5 		
Issuance of Notes Receivable to Affiliated Companies		(525.0)			(615.0)			(271.0)		
Return of Capital Contributions from Unconsolidated Subsidiaries		5.0 			— 			— 		
Capital Contributions to Subsidiaries		(335.0)			— 			(664.0)		
	
Net Cash Flows Used for Investing Activities		(895.3)			(666.7)			(929.5)		
							
FINANCING ACTIVITIES		 		 		 	
	
Capital Contributions from Member		335.0 			— 			664.0 		
Issuance of Long-term Debt – Nonaffiliated		519.5 			688.0 			321.0 		

Retirement of Long-term Debt – Nonaffiliated		— 			(85.0)			(50.0)		
	
Dividends Paid to Member		(5.0)			— 			— 		
	
Net Cash Flows from Financing Activities		849.5 			603.0 			935.0 		
							
Net Change in Cash and Cash Equivalents		— 			— 			— 		
Cash and Cash Equivalents at Beginning of Period		— 			— 			— 		
Cash and Cash Equivalents at End of Period		$	— 			$	— 			$	— 		
							
See Condensed Notes to Condensed Financial Information beginning on page S-18.	
S-17

SCHEDULE I
AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL INFORMATION

1.   Summary of Significant Accounting Policies	
 	
2.   Commitments, Guarantees and Contingencies	
 	
3.   Financing Activities	
 	
4.   Related Party Transactions	
S-18

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The condensed financial information of AEPTCo Parent is required as a result of the restricted net assets of AEPTCo consolidated subsidiaries exceeding 25% of AEPTCo consolidated net assets as of December 31, 2020.  AEPTCo Parent is the direct holding company for the seven State Transcos.  The primary source of income for AEPTCo Parent is equity in its subsidiaries’ earnings. AEPTCo Parent financial statements should be read in conjunction with the AEPTCo consolidated financial statements and the accompanying notes thereto. For purposes of these condensed financial statements, AEPTCo wholly-owned and majority-owned subsidiaries are recorded based upon its proportionate share of the subsidiaries’ net assets (similar to presenting them on the equity method).

Income Taxes

AEPTCo Parent joins in the filing of a consolidated federal income tax return with its affiliates in the AEP System.  The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries with taxable income reducing their current tax expense proportionately.  The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of AEP Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss, the loss of the AEP Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.

2.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

AEPTCo Parent and its subsidiaries are parties to legal matters.  For further discussion, see Note 6 - Commitments, Guarantees and Contingencies included in the 2020 Annual Report.

3.  FINANCING ACTIVITIES

For discussion of Financing Activities, see Note 14 - Financing Activities to AEPTCo’s audited consolidated financial statements included in the 2020 Annual Report.

4.  RELATED PARTY TRANSACTIONS

Payments on Behalf of Subsidiaries

Due to occasional time sensitivity and complexity of payments, Parent makes certain insurance, tax and other payments on behalf of subsidiary companies.  Parent is then fully reimbursed by the subsidiary companies. AEPTCo Parent also makes convenience payments on behalf of its State Transcos. AEPTCo Parent is then fully reimbursed by its State Transcos.

Long-term Lending to Subsidiaries

AEPTCo Parent enters into debt arrangements with nonaffiliated entities. AEPTCo Parent has long-term debt of $3.9 billion and $3.4 billion as of December 31, 2020 and 2019, respectively. AEPTCo Parent uses the proceeds from these nonaffiliated debt arrangements to make affiliated loans to its State Transcos using the same interest rates and maturity dates as the nonaffiliated debt arrangements. AEPTCo Parent has recorded Notes Receivable – Affiliated of $3.9 billion and $3.4 billion as of December 31, 2020 and 2019, respectively. Related to these nonaffiliated and affiliated debt arrangements, AEPTCo Parent has recorded Accrued Interest of $24 million and $19 million as of December 31, 2020 and 2019, respectively. AEPTCo Parent has also recorded Accounts Receivable – Affiliated Companies of $27 million and $23 million as of December 31, 2020 and 2019, respectively. AEPTCo Parent has recorded Interest Income – Affiliated of $150 million, $124 million and $105 million for the years ended December 31, 2020, 2019 and 2018, respectively, related to the Notes Receivable – Affiliated. AEPTCo Parent has recorded Interest Expense of $148 million, $122 million and $103 million for the years ended December 31, 2020, 2019 and 2018, respectively, related to the nonaffiliated debt arrangements.
S-19

Short-term Lending to Subsidiaries

Parent uses a commercial paper program to meet the short-term borrowing needs of subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  The program also allows some direct borrowers to invest excess cash with Parent.

Interest expense related to AEPTCo Parent’s short-term borrowing is included in Interest Expense on AEPTCo Parent’s statements of income.  AEPTCo Parent incurred immaterial interest expense for amounts borrowed from AEP affiliates for the years ended December 31, 2020, 2019 and 2018.

Interest income related to AEPTCo Parent’s short-term lending is included in Interest Income – Affiliated on AEPTCo Parent’s statements of income.  AEPTCo Parent earned interest income for amounts advanced to AEP affiliates of $2 million, $2 million and $1 million for the year ended December 31, 2020, 2019 and 2018, respectively.
S-20

EXHIBIT INDEX

The documents listed below are being filed or have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof.  Exhibits (“Ex”) not identified as previously filed are filed herewith.  Exhibits designated with a dagger (†) are management contracts or compensatory plans or arrangements required to be filed as an Exhibit to this Form.  Exhibits designated with an asterisk (*) are filed herewith.

Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
 	 	 	
AEP‡   File No. 1-3525	 	 	
 	 	 	 	 	
3(a)		Composite of the Restated Certificate of Incorporation of AEP, dated April 26, 2019.		Form 10-Q, Ex 3, June 30, 2019	
					
3(b)		Composite By-Laws of AEP, as amended as of October 20, 2015.		Form 8-K, Ex 3(b) dated October 21, 2015	
					
4(a)		Indenture (for unsecured debt securities), dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee.		Registration Statement No. 333-86050, Ex 4(a)(b)(c)
Registration Statement No. 333-105532, Ex 4(d)(e)(f)
Registration Statement No. 333-200956, Ex 4(b)
Registration Statement No. 333-222068, Ex 4(b) Registration Statement No. 333-249918, Ex 4(b)(c)	
					
4(a)1		Company Order and Officers Certificate to The Bank of New York Mellon Trust Company, N.A. dated November 20, 2020 establishing terms of 0.75% Senior Notes Series M due 2023, 1.00% Senior Notes, Series N due 2025 and Floating Rate Notes, Series A due 2023.		Form 8-K, Ex 4(a) dated November 18, 2020	
					
4(a)2		Purchase Contract and Pledge Agreement, dated as of March 19, 2019, between the Company and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent, collateral agent, custodial agent and securities intermediary.		Registration Statement No. 333-249918, Ex 4(h)	
					
4(a)3		Purchase Contract dated as of August 14, 2020, between the Company and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent, collateral agent, custodial agent and securities intermediary.		Registration Statement No. 333-249918, Ex 4(i)	
					
4(a)4		Junior Subordinated Indenture, dated March 1, 2008, between the Company and The Bank of New York Mellon Trust Company, N.A., as Trustee for the Junior Subordinated Debentures.		Registration Statement No. 333-156387, Ex 4(c) (d)
Registration Statement No. 333-249918, Ex 4(f)(g)	
					
4(b)		First Amendment to Fourth Amended and Restated Credit Agreement dated June 30, 2016 among AEP, the banks, financial institutions and other institutional lenders listed on the signature pages thereof and Wells Fargo Bank, N.A., as Administrative Agent.		Form 10-Q, Ex 4, September 30, 2018	
E-1

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	

*4(c)		Description of Securities.			
 	 	 	 	 	
4(d)		Credit Agreement among AEP, initial lenders and PNC Bank, National Association as Administrative Agent.		Form 10-Q, Ex 4.3, March 31, 2020	
					
4(e)		Distribution Agreement, dated November 6, 2020, between American Electric Power Company, Inc. and Credit Suisse Securities (USA) LLC, Barclays Capital Inc., BofA Securities, Inc., BNY Mellon Capital Markets, LLC, Citigroup Global Markets Inc., Scotia Capital (USA) Inc., Credit Suisse Capital LLC, Barclays Bank PLC, Bank of America, N.A. and Citibank, N.A.		Form 8-K, Ex 1.1, November 6, 2020	
					
10(a)		Lease Agreements, dated as of December 1, 1989, between AEGCo or I&M and Wilmington Trust Company, as amended.		Registration Statement No. 33-32752, Ex 28(c)(1-6)(C)
Registration Statement No. 33-32753, Ex 28(a)(1-6)(C)
AEGCo 1993 Form 10-K, Ex 10(c)(1-6)(B)
I&M 1993 Form 10-K, Ex 10(e)(1-6)(B)	
					
10(b)		Consent Decree with U.S. District Court dated October 9, 2007, as modified July 17, 2019.		Form 8-K, Ex. 10 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
Form 10-Q, Ex 10, June 30, 2019	
					
†10(c)		AEP Retainer Deferral Plan for Non-Employee Directors, as Amended and Restated effective October 1, 2020.		Form 10-Q, Ex 10.2, September 30, 2020	
					
†10(d)		AEP Stock Unit Accumulation Plan for Non-Employee Directors as amended October 1, 2020.		Form 10-Q, Ex 10.3, September 30, 2020	
					
†10(e)		AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2020.		2019 Form 10-K, Ex 10(e)	
					
†10(e)(1)		Guaranty by AEP of AEPSC Excess Benefits Plan.		1990 Form 10-K, Ex 10(h)(1)(B)	
					
†10(f)		AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011 (Non-Qualified).		2010 Form 10-K, Ex 10	
					
†10(f)(1)(A)		Amendment to AEP System Supplemental Retirement Savings Plan, as Amended and Restated as of January 1, 2011 (Non-Qualified).		2014 Form 10-K, Ex 10(l)(1)(A)	
					
†10(f)(2)(A)		Second Amendment to AEP System Supplemental Retirement Savings Plan, as Amended and Restated as of January 1, 2011 (Non-Qualified).		2019 Form 10-K, Ex 10(f)(2)(A)	
					
†10(g)		AEPSC Umbrella Trust for Executives.		1993 Form 10-K, Ex 10(g)(3)	
					
E-2

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
 	 	 	
†10(g)(1)(A)		First Amendment to AEPSC Umbrella Trust for Executives.		2008 Form 10-K, Ex 10(l)(3)(A)	
					
†10(g)(2)(A)		Second Amendment to AEPSC Umbrella Trust for Executives.		2018 Form 10-K, Ex 10(g)(2)(A)	
					
†10(h)		AEP System Incentive Compensation Deferral Plan Amended and Restated as of June 1, 2019.		Form 10-Q, Ex 10(1), September 30, 2019	
					
†10(h)(1)(A)		First Amendment to AEP System Incentive Compensation Deferral Plan, as Amended and Restated effective January 1, 2008.		2011 Form 10-K, Ex 10(p)(1)(A)	
 	 	 	 	 	
†10(h)(2)(A)		Second Amendment to AEP System Incentive Compensation Deferral Plan, as Amended and Restated effective January 1, 2008.		2014 Form 10-K, Ex 10(q)(2)(A)	
					
†10(i)		AEP Change In Control Agreement, as Revised Effective January 1, 2017.		Form 10-Q, Ex 10(c) , September 30, 2016	
					
†10(j)		Amended and Restated AEP System Long-Term Incentive Plan as of September 21, 2016.		Form 10-Q, Ex 10(a) , September 30, 2016	
					
†10(j)(1)(A)		Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.		Form 10-Q, Ex 10(a), March 30, 2018	
					
†10(j)(2)(A)		Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan as Amended and Restated.		Form 10-Q, Ex 10(b), March 30, 2018	
					
†10(k)		AEP System Stock Ownership Requirement Plan Amended and Restated effective June 20, 2017.		Form 10-Q, Ex 10, June 30, 2017	
					
†10(k)(A)		AEP System Stock Ownership Requirement Plan Amended and Restated effective October 1, 2020.		Form 10-Q, Ex 10.1, September 30, 2020	
					
†10(l)		Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2020.		2019 Form 10-K, Ex 10(l)	
					
†10(m)		AEP Executive Severance Plan Amended and Restated effective October 24, 2016.		Form 10-Q, Ex 10(d) , September 30, 2016	
					
†10(m)1(A)		AEP Executive Severance Plan Amended effective June 17, 2020.		Form 10-Q, Ex 10, June 30, 2020	
					
*†10(n)		AEP Executive Severance Plan Amended effective January 4, 2021.			
					
†10(o)		Severance, Stock Award, Release of All Claims and Noncompetition Agreement dated October 21, 2020 between AEPSC and Lana Hillebrand.		Form 10-Q, Ex 10.4 dated September 30, 2020	
E-3

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	

†10(p)		AEP Aircraft Timesharing Agreement dated October 1, 2019 between American Electric Power Service Corporation and Nicholas K. Akins.		Form 10-Q, Ex 10(2), September 30, 2019	
					
*21		List of subsidiaries of AEP.			
					
*23		Consent of PricewaterhouseCoopers LLP.			
					
*24		Power of Attorney.			
					
*31(a)		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*31(b)		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*32(a)		Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
			 	 	
*32(b)		Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
101.INS		XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.			
					
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104		Cover Page Interactive Data File. Formatted as inline XBRL and contained in Exhibit 101.			
					
AEP TEXAS‡   File No. 333-221643			
					
3(a)		Composite of the Restated Certificate of Incorporation, as amended.		Registration No. 333-221643, Ex 3(a)	
					
3(b)		Bylaws.		Registration No. 333-221643, Ex 3(b)	
					
E-4

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
 	 	 	
4(a)		Indenture, dated as of September 1, 2017, between AEP Texas Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee.		Registration No. 333-221643, Ex 4(a)-1,4(a)-2; Registration No. 333-228657, Ex 4(a)-4,4(a)-5; Registration No. 333-230613, Ex 4(a)(b)	
					
4(b)		Company Order and Officer’s Certificate to The Bank of New York Mellon Trust Company, N.A. dated May 1, 2019 establishing the terms of 4.15% Senior Notes, Series G due 2049.		Form 8-K Ex 4(a) dated April 29, 2019	
					
4(c)		Company Order and Officer’s Certificate to The Bank of New York Mellon Trust Company, N.A. dated December 5, 2019 establishing the terms of 3.45% Senior Notes, Series H due 2050.		Form 8-K Ex 4(a) dated December 6, 2019	
					
4(d)		Company Order and Officer’s Certificate to The Bank of New York Mellon Trust Company, N.A. dated July 1, 2020 establishing the terms of 2.10% Senior Notes, Series I due 2030.		Form 8-K Ex. 4(a) dated July 1, 2020	
					
*23		Consent of PricewaterhouseCoopers LLP.			
					
*24		Power of Attorney.			
					
*31(a)		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*31(b)		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*32(a)		Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
*32(b)		Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
101.INS		XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.			
					
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E-5

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
 	 	 	
101.PRE		XBRL Taxonomy Extension Presentation Linkbase.			
					
104		Cover Page Interactive Data File. Formatted as inline XBRL and contained in Exhibit 101.			
					
AEPTCo‡   File No. 333-217143			
					
3(a)		Limited Liability Company Agreement of AEP Transmission Company, LLC dated as of January 27, 2006.		Registration Statement No. 333-217143, Ex 3(a)	
					
3(b)		First Amendment to Limited Liability Company Agreement dated as of May 21, 2013.		Registration Statement No. 333-217143, Ex 3(b)	
					
4(a)		Indenture, dated as of November 1, 2016, between AEP Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A., as Trustee.		Registration Statement No. 333-217143, Ex 4(a)-1, 4(a)-2
Registration Statement No. 333-225325, Ex 4(b)(c)(d)	
					
4(b)		Company Order and Officers’ Certificate to The Bank of New York Mellon Trust Company, N.A. dated September 7, 2018 establishing the terms of the 4.25% Senior Notes, Series J due 2048.		Form 8-K, Ex 4(a) dated September 7, 2018	
					
4(c)		Company Order and Officers’ Certificate to The Bank of New York Mellon Trust Company, N.A. dated June 12, 2019 establishing the terms of the 3.80% Senior Notes, Series K due 2049.		Form 8-K Ex 4(a) dated June 12, 2019	
					
4(d)		Company Order and Officers’ Certificate to The Bank of New York Mellon Trust Company, N.A. dated September 11, 2019 establishing the terms of the 3.15% Senior Notes, Series L due 2049.		Form 8-K Ex 4(a) dated September 9, 2019	
					
4(e)		Company Order and Officers’ Certificate to The Bank of New York Mellon Trust Company, N.A. dated April 1, 2020 establishing the terms of the 3.65% Senior Notes, Series M due 2050.		Form 8-K Ex 4(a) dated April 1, 2020	
					
4(f)		Note Purchase Agreement, dated as of October 18, 2012 between AEP Transmission Company, LLC and the Initial Purchasers.		Registration Statement No. 333-217143, Ex 4(c)-1	
					
4(f)(1)		Supplement to Note Purchase Agreement, dated as of November 7, 2013 between AEP Transmission Company, LLC and the Initial Purchasers.		Registration Statement No. 333-217143, Ex 4(c)-2	
					
4(f)(2)		Supplement to Note Purchase Agreement, dated as of November 14, 2014 between AEP Transmission Company, LLC and the Initial Purchasers.		Registration Statement No. 333-217143, Ex 4(c)-3	
E-6

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	

*23		Consent of PricewaterhouseCoopers LLP.			
					
*24		Power of Attorney.			
					
*31(a)		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*31(b)		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*32(a)		Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
*32(b)		Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
101.INS		XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.			
					
101.SCH		XBRL Taxonomy Extension Schema.			
					
101.CAL		XBRL Taxonomy Extension Calculation Linkbase.			
					
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101.LAB		XBRL Taxonomy Extension Label Linkbase.			
					
101.PRE		XBRL Taxonomy Extension Presentation Linkbase.			
					
104		Cover Page Interactive Data File. Formatted as inline XBRL and contained in Exhibit 101.			
					
APCo‡   File No. 1-3457			
					
3(a)		Composite of the Restated Articles of Incorporation of APCo, amended as of March 7, 1997.		1996 Form 10-K, Ex 3(d)	
					
3(b)		Composite By-Laws of APCo, amended as of February 26, 2008.		2007 Form 10-K, Ex 3(b)	
					
E-7

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
 	 	 	
4(a)		Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The Bank of New York, As Trustee.		Registration Statement No. 333-45927, Ex 4(a)(b)
Registration Statement No. 333-49071, Ex 4(b)
Registration Statement No. 333-84061, Ex 4(b)(c)
Registration Statement No. 333-100451, Ex 4(b)
Registration Statement No. 333-116284, Ex 4(b)(c)
Registration Statement No. 333-123348, Ex 4(b)(c)
Registration Statement No. 333-136432, Ex 4(b)(c)(d)
Registration Statement No. 333-161940, Ex 4(b)(c)(d)
Registration Statement No. 333-182336, Ex 4(b)(c)
Registration Statement No. 333-200750, Ex 4(b)(c)
Registration Statement No. 333-214448, Ex 4(b)
Registration Statement No. 333-236613, Ex 4(b)(c)	
					
4(b)		Company Order and Officers Certificate to The Bank of New York Mellon Trust Company, N.A. dated May 14, 2020 of 3.70% Senior Notes Series Z due 2050.		Form 8-K, Ex 4(a) dated May 14, 2020	
					
10(a)		Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.		2013 Form 10-K, Ex 10(a)	
					
10(d)		Consent Decree with U.S. District Court dated October 9, 2007, as modified July 17, 2019.		Form 8-K, Ex. 10 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
Form 10-Q, Ex 10, June 30, 2019	
					
*23		Consent of PricewaterhouseCoopers LLP.			
					
*24		Power of Attorney.			
					
*31(a)		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*31(b)		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*32(a)		Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
*32(b)		Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
E-8

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
 	 	 	
101.INS		XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.			
					
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104		Cover Page Interactive Data File. Formatted as inline XBRL and contained in Exhibit 101.			
					
I&M‡   File No. 1-3570			
					
3(a)		Composite of the Amended Articles of Acceptance of I&M, dated of March 7, 1997.		1996 Form 10-K, Ex 3(c)	
					
3(b)		Composite By-Laws of I&M, amended as of February 26, 2008.		2007 Form 10-K, Ex 3(b)	
					
4(a)		Indenture (for unsecured debt securities), dated as of October 1, 1998, between I&M and The Bank of New York, as Trustee.		Registration Statement No. 333-88523, Ex 4(a)(b)(c)
Registration Statement No. 333-58656, Ex 4(b)(c)
Registration Statement No. 333-108975, Ex 4(b)(c)(d)
Registration Statement No. 333-136538, Ex 4(b)(c)
 Registration Statement No. 333-156182, Ex 4(b)
Registration Statement No. 333-185087, Ex 4(b)
Registration Statement No. 333-207836, Ex 4(b)
Registration Statement No. 333-225103, Ex 4(b)(c)(d)	
					
4(b)		Company Order and Officers Certificate to The Bank of New York Mellon Trust Company, N.A. dated August 8, 2018 of 4.25% Series N due 2048.		Form 8-K, Ex 4(a) dated August 8, 2018	
					
10(a)		Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.		2013 Form 10-K, Ex 10(a)	
					
10(b)		Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended.		Registration Statement No. 33-32752, Ex 28(b)(1)(A)(B)	
					
E-9

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
 	 	 	
10(c)		Consent Decree with U.S. District Court dated October 9, 2007, as modified July 17, 2019.		Form 8-K, Ex. 10 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
Form 10-Q, Ex 10, June 30, 2019	
					
10(d)		Lease Agreements, dated as of December 1, 1989, between I&M and Wilmington Trust Company, as amended.		Registration Statement No. 33-32753, Ex 28(a)(1-6)(C)
1993 Form 10-K, Ex 10(e)(1-6)(B)	
					
*23		Consent of PricewaterhouseCoopers LLP.			
					
*24		Power of Attorney.			
					
*31(a)		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*31(b)		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*32(a)		Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
*32(b)		Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
101.INS		XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.			
					
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101.LAB		XBRL Taxonomy Extension Label Linkbase.			
					
101.PRE		XBRL Taxonomy Extension Presentation Linkbase.			
					
104		Cover Page Interactive Data File. Formatted as inline XBRL and contained in Exhibit 101.			
			
OPCo‡   File No. 1-6543			
					
3(a)		Composite of the Amended Articles of Incorporation of OPCo, dated June 3, 2002.		Form 10-Q, Ex 3(e), June 30, 2002	
					
3(b)		Amended Code of Regulations of OPCo.		Form 10-Q, Ex 3(b), June 30, 2008	
					
E-10

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
 	 	 	
4(a)		Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo and Bankers Trust Company (now The Bank of New York Mellon Trust Company, N.A. as assignee of Deutsche Bank Trust Company Americas), as Trustee.		Registration Statement No. 333-49595, Ex 4(a)(b)(c)
Registration Statement No. 333-106242, Ex 4(b)(c)(d)
Registration Statement No. 333-127913, Ex 4(b)(c)
Registration Statement No. 333-139802, Ex 4(b)(c)(d)
Registration Statement No. 333-161537, Ex 4(b)(c)(d)
 Registration Statement No. 333-211192, Ex 4(b)
Registration Statement No. 333-230094, Ex 4(b)	
					
4(a)(1)		Resignation of Deutsche Bank Trust Company Americas, as Trustee and appointment of The Bank of New York Mellon Trust Company, N.A. as Trustee of Indenture with OPCo dated as of September 1, 1997.		Form 8-K, Item 8.01 dated October 8, 2018	
					
4(b)		Indenture (for unsecured debt securities), dated as of February 1, 2003, between OPCo and Bank One, N.A., as Trustee.		Registration Statement No. 333-127913, Ex 4(d)(e)(f)	
					
4(c)		Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo (predecessor in interest to OPCo) and Bankers Trust Company, as Trustee.		Registration Statement No. 333-54025, Ex 4(a)(b)(c)(d)
Registration Statement No. 333-128174, Ex 4(b)(c)(d)
 Registration Statement No. 333-150603, Ex 4(b)	
					
4(d)		Indenture (for unsecured debt securities), dated as of February 1, 2003, between CSPCo (predecessor in interest to OPCo) and Bank One, N.A., as Trustee.		Registration Statement No. 333-128174, Ex 4(e)(f)(g)
 Registration Statement No. 333-150603, Ex 4(b)	
					
4(e)		First Supplemental Indenture, dated as of December 31, 2011, by and between OPCo and The Bank of New York Mellon Trust Company, N.A., as trustee, supplementing the Indenture dated as of September 1, 1997 between CSPCo (predecessor in interest to OPCo) and the trustee.		Form 8-K, Ex 4.1 dated January 6, 2012	
					
4(f)		Third Supplemental Indenture, dated as of December 31, 2011, by and between OPCo and The Bank of New York Mellon Trust Company, N.A., as trustee, supplementing the Indenture dated as of February 14, 2003 between CSPCo (predecessor in interest to OPCo) and the trustee.		Form 8-K, Ex 4.2 dated January 6, 2012	
					
4(g)		Company Order and Officers Certificate to The Bank of New York Mellon Trust Company, N.A. dated May 22, 2019 establishing the terms of the 4.00% Senior Notes Series O due 2049.		Form 8-K, Ex 4(a) dated May 22, 2019	
					
E-11

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
 	 	 	
4(h)		Company Order and Officers Certificate to The Bank of New York Mellon Trust Company, N.A. dated March 17, 2020 establishing the terms of the 2.60% Senior Notes Series P due 2030.		Form 8-K, Ex 4(a) dated March 17, 2020	
					
4(i)		Company Order and Officers Certificate to The Bank of New York Mellon Trust Company, N.A. dated January 7, 2021 establishing the terms of the 1.65% Senior Notes Series Q due 2031.		Form 8-K dated January 7, 2021 Ex 4(a)	
					
10(a)		Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.		2013 Form 10-K, Ex 10(a)	
					
10(b)		Consent Decree with U.S. District Court dated October 9, 2007, as modified July 17, 2019.		Form 8-K, Ex. 10 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
Form 10-Q, Ex 10, June 30, 2019	
					
*23		Consent of PricewaterhouseCoopers LLP.			
					
*24		Power of Attorney.			
					
*31(a)		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*31(b)		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*32(a)		Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
*32(b)		Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
101.INS		XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.			
					
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101.LAB		XBRL Taxonomy Extension Label Linkbase.			
					
101.PRE		XBRL Taxonomy Extension Presentation Linkbase.			
					
E-12

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
 	 	 	
104		Cover Page Interactive Data File. Formatted as inline XBRL and contained in Exhibit 101.			
			
PSO‡   File No. 0-343			
					
3(a)		Certificate of Amendment to Restated Certificate of Incorporation of PSO.		Form 10-Q, Ex 3(a), June 30, 2008	
					
3(b)		Composite By-Laws of PSO amended as of February 26, 2008.		2007 Form 10-K, Ex 3 (b)	
					
4(a)		Indenture (for unsecured debt securities), dated as of November 1, 2000, between PSO and The Bank of New York, as Trustee.		Registration Statement No. 333-100623, Ex 4(a)(b)
Registration Statement No. 333-114665, Ex 4(b)(c)
Registration Statement No. 333-133548, Ex 4(b)(c)
Registration Statement No. 333-156319, Ex 4(b)(c)	
					
4(b)		Eighth Supplemental Indenture, dated as of November 13, 2009 between PSO and The Bank of New York Mellon, as Trustee, establishing terms of the 5.15% Senior Notes, Series H, due 2019.		Form 8-K, Ex 4(a), dated November 13, 2009	
					
4(c)		Ninth Supplemental Indenture, dated as of January 19, 2011 between PSO and The Bank of New York Mellon Trust Company, N.A., as Trustee, establishing terms of 4.40% Senior Notes, Series I, due 2021.		Form 8-K, Ex 4(a) dated January 20, 2011	
					
*4(d)		Credit Agreement dated as of January 19, 2021 among PSO as Borrower, Initial Lenders and Sumitomo Mitsui Banking Corporation as Administrative Agent.			
					
*23		Consent of PricewaterhouseCoopers LLP.			
					
*24		Power of Attorney.			
					
*31(a)		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*31(b)		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*32(a)		Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
*32(b)		Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
E-13

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
 	 	 	
101.INS		XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.			
					
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101.PRE		XBRL Taxonomy Extension Presentation Linkbase.			
					
104		Cover Page Interactive Data File. Formatted as inline XBRL and contained in Exhibit 101.			
			
SWEPCo‡   File No. 1-3146			
					
3(a)		Composite of Amended Restated Certificate of Incorporation of SWEPCo.		2008 Form 10-K, Ex 3(a)	
					
3(a)(A)		Amendment to Amended Restated Certificate of Incorporation.		Form 8-K Ex 3.1 dated September 1, 2020	
					
3(b)		Composite By-Laws of SWEPCo amended as of February 26, 2008.		2007 Form 10-K, Ex 3(b)	
					
4(a)		Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCo and The Bank of New York, as Trustee.		Registration Statement No. 333-96213
Registration Statement No. 333-87834, Ex 4(a)(b)
 Registration Statement No. 333-100632, Ex 4(b)
Registration Statement No. 333-108045, Ex 4(b)
Registration Statement No. 333-145669, Ex 4(c)(d)
Registration Statement No. 333-161539, Ex 4(b)(c)
Registration Statement No. 333-194991, Ex 4(b)(c)
Registration Statement No. 333-208535, Ex 4(b)(c)
Registration Statement No. 333-226856, Ex 4(b)(c)
Registration Statement No. 333-238159, Ex 4(b)	
					
*23		Consent of PricewaterhouseCoopers LLP.			
					
*24		Power of Attorney.			
					
*31(a)		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
E-14

															
Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
 	 	 	
*31(b)		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.			
					
*32(a)		Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
*32(b)		Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.			
					
*95		Mine Safety Disclosure.			
					
101.INS		XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.			
					
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101.CAL		XBRL Taxonomy Extension Calculation Linkbase.			
					
101.DEF		XBRL Taxonomy Extension Definition Linkbase.			
					
101.LAB		XBRL Taxonomy Extension Label Linkbase.			
					
101.PRE		XBRL Taxonomy Extension Presentation Linkbase.			
					
104		Cover Page Interactive Data File. Formatted as inline XBRL and contained in Exhibit 101.			

‡ Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants.  The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.

The agreements and other documents filed as exhibits to this report are not intended to provide factual information or other disclosure other than with respect to the terms of the agreements or other documents themselves, and you should not rely on them for that purpose. In particular, any representations and warranties made by us in these agreements or other documents were made solely within the specific context of the relevant agreement or document and may not describe the actual state of affairs as of the date they were made or at any other time.
E-15

Exhibit 4(c). Description of Securities.

As of the date of the Annual Report on Form 10-K of which this exhibit is a part, American Electric Power Company, Inc. (the “Company”) has two classes of securities registered under Section 12(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”): (1) our common stock, par value $6.50 per share, (2) our 6.125% Equity Units issued in 2019 and (3) our 6.125% Equity Units issued in 2020.

Description of Common Stock

The following description of our common stock is a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to our Amended and Restated Certificate of Incorporation, as amended and our By-Laws, each of which are incorporated by reference as an exhibit to the Annual Report on Form 10-K of which this exhibit is a part. We encourage you to read our Certificate of Incorporation, our By-Laws and the applicable provisions of New York Business Corporation Law for additional information..

Our authorized capital stock currently consists of 600,000,000 shares of common stock, par value $6.50 per share. ____,____,____ shares of our common stock were issued and outstanding as of February ___, 2021. Our common stock is listed on the NASDAQ Stock Market LLC. Computershare Trust Company, N.A., P.O. Box 43081, Providence, Rhode Island 02940-3081, is the transfer agent and registrar for our common stock.

Dividend Rights

The holders of our common stock are entitled to receive the dividends declared by our board of directors provided funds are legally available for such dividends. Our income derives from our common stock equity in the earnings of our subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances.

Voting Rights

The holders of our common stock are entitled to one vote for each share of common stock held.

Rights Upon Liquidation

If we are liquidated, holders of our common stock will be entitled to receive pro rata all assets available for distribution to our shareholders after payment of our liabilities, including liquidation expenses.

Pre-emptive Rights

    The holders of our common stock, whether heretofore or hereafter issued, have no preemptive rights with respect to (1) any shares of the corporation of any class or series, or (2) any other security of the corporation convertible into or carrying rights or options to purchase such shares.

Restrictions on Dealing with Existing Shareholders

We are subject to Section 513 of New York's Business Corporation Law, which provides that no domestic corporation may purchase or agree to purchase more than 10% of its stock from a shareholder who has held the shares for less than two years at any price that is higher than the market price unless the

transaction is approved by both the corporation's board of directors and a majority of the votes of all outstanding shares entitled to vote thereon at a meeting of shareholders, unless the Certificate of Incorporation requires a greater percentage of the votes of the outstanding shares to approve or the corporation offers to purchase shares from all the holders on the same terms. Our Certificate of Incorporation does not currently provide for a higher percentage.

Description of 2019 Equity Units

In this Description of the Equity Units, “AEP,” “we”,” “us,” “our” and the “Company” refer only to American Electric Power Company, Inc. and any successor obligor, and not to any of its subsidiaries.

The following is a summary of some of the terms of the Equity Units. This summary, together with the summaries of the terms of the purchase contracts, the purchase contract and pledge agreement and the Notes set forth under the captions “Description of the Purchase Contracts,” “Certain Provisions of the Purchase Contract and Pledge Agreement” and “Description of the Junior Subordinated Debentures” in this prospectus supplement, contain a description of the material terms of the Equity Units, but are only summaries and are not complete. This summary is subject to and is qualified by reference to all the provisions of the purchase contract and pledge agreement, the subordinated indenture (as defined under “Description of the Junior Subordinated Debentures— Ranking”), the supplemental indenture (as defined under “Description of the Junior Subordinated Debentures—Ranking”), the Notes and the form of remarketing agreement, which has been attached as an exhibit to the purchase contract and pledge agreement, including the definitions of certain terms used therein, forms of which have been or will be filed and incorporated by reference as exhibits to the registration statement of which this prospectus supplement and the accompanying base prospectus form a part.

General

We will issue the Equity Units under the purchase contract and pledge agreement among us and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent (the “purchase contract agent”), collateral agent (the “collateral agent”), custodial agent (the “custodial agent”) and securities intermediary. The Equity Units may be either Corporate Units or Treasury Units. The Equity Units will initially consist of 14,000,000 Corporate Units (or 16,100,000 Corporate Units if the underwriters exercise their option to purchase additional Corporate Units in full), each with a stated amount of $50.00.

Each Corporate Unit offered will consist of:

•a purchase contract under which
•the holder will agree to purchase from us, and we will agree to sell to the holder, on March 15, 2022 (or if such day is not a business day, the following business day), which we refer to as the “purchase contract settlement date,” or earlier upon early settlement, for $50.00, a number of shares of our common stock equal to the applicable settlement rate described under “Description of the Purchase Contracts—Purchase of Common Stock,” “Description of the Purchase Contracts—Early Settlement” or “Description of the Purchase Contracts—Early Settlement Upon a Fundamental Change,” as the case may be, plus, in the case of an early settlement upon a fundamental change, the number of make-whole shares; and
•we will pay the holder quarterly contract adjustment payments at the rate of 2.725% per year on the stated amount of $50.00, or $1.3625 per year, subject to our right to defer
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such contract adjustment payments as described under “Description of the Purchase Contracts—Contract Adjustment Payments,” and
either:
•a 1/20 undivided beneficial ownership interest in a $1,000 principal amount 3.40% junior subordinated debenture due 2024 issued by us, and under which we will pay to the holder 1/20 of the interest payment on a $1,000 principal amount Note at the initial rate of 3.40%, or $34.00 per year per $1,000 principal amount of Notes, subject to our right to defer such interest payments as described under “Description of the Junior Subordinated Debentures—Option to Defer Interest Payments;” or
•following a successful optional remarketing, the applicable ownership interest in a portfolio of U.S. Treasury securities, which we refer to as the “Treasury portfolio.”
“Applicable ownership interest” means, with respect to the Treasury portfolio,
(1)a 1/20 undivided beneficial ownership interest in $1,000 face amount of U.S. Treasury securities (or principal or interest strips thereof) included in the Treasury portfolio that mature on or prior to the purchase contract settlement date; and
(2)for the scheduled interest payment occurring on the purchase contract settlement date, a 0.0425% undivided beneficial ownership interest in $1,000 face amount of U.S. Treasury securities (or principal or interest strips thereof) that mature on or prior to the purchase contract settlement date.
If U.S. Treasury securities (or principal or interest strips thereof) that are to be included in the Treasury portfolio in connection with a successful optional remarketing have a yield that is less than zero, the Treasury portfolio will consist of an amount in cash equal to the aggregate principal amount at maturity of the U.S. Treasury securities described in clauses (1) and (2) above. If the provisions set forth in this paragraph apply, references to “Treasury security” and “U.S. Treasury securities (or principal or interest strips thereof)” in connection with the Treasury portfolio will, thereafter, be deemed to be references to such amount of cash.
So long as the Equity Units are in the form of Corporate Units, the related undivided beneficial ownership interest in the Note or the applicable ownership interest in the Treasury portfolio described in clause (1) of the definition of “applicable ownership interest” above (or $50.00 in cash, if the immediately preceding paragraph applies), as the case may be, will be pledged to us through the collateral agent to secure the holders’ obligations to purchase our common stock under the related purchase contracts.
Creating Treasury Units by Substituting a Treasury Security for a Note
Each holder of 20 Corporate Units may create, at any time other than after a successful remarketing or during a blackout period (as defined below), 20 Treasury Units by substituting for a Note a zero-coupon U.S. Treasury security (for example, CUSIP No. 912820ZW0) with a principal amount at maturity equal to $1,000 and maturing on February 15, 2022, which we refer to as a “Treasury security.” This substitution would create 20 Treasury Units and the Note would be released from the pledge under the purchase contract and pledge agreement and delivered to the holder and would be tradable and transferable separately from the Treasury Units. Because Treasury securities and Notes are issued in integral multiples of $1,000, holders of Corporate Units may make the substitution only in integral multiples of 20 Corporate Units. After a successful remarketing, holders may not create Treasury Units from Corporate Units or recreate Corporate Units from Treasury Units.

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Each Treasury Unit will consist of:
•a purchase contract under which
•the holder will agree to purchase from us, and we will agree to sell to the holder, on the purchase contract settlement date, or earlier upon early settlement, for $50.00, a number of shares of our common stock equal to the applicable settlement rate, plus, in the case of an early settlement upon a fundamental change, the number of make-whole shares; and
•we will pay the holder quarterly contract adjustment payments at the rate of 2.725% per year on the stated amount of $50.00, or $1.3625 per year, subject to our right to defer the contract adjustment payments; and
•a 1/20 undivided beneficial ownership interest in a Treasury security.
The term “blackout period” means the period (1) if we elect to conduct an optional remarketing, from 4:00 p.m., New York City time, on the second business day (as defined below) immediately preceding the first day of the optional remarking period until the settlement date of such optional remarketing or the date we announce that such remarketing was unsuccessful and (2) after 4:00 p.m., New York City time, on the second business day immediately preceding the first day of the final remarketing period.
The term “business day” means any day that is not a Saturday or Sunday or a day on which banking institutions in The City of New York are authorized or required by law or executive order to close.
The Treasury Unit holder’s beneficial ownership interest in the Treasury security will be pledged to us through the collateral agent to secure the holder’s obligation to purchase our common stock under the related purchase contracts.
To create 20 Treasury Units, a holder is required to:
•deposit with the collateral agent a Treasury security that has a principal amount at maturity of $1,000, which must be purchased in the open market at the expense of the Corporate Unit holder, unless otherwise owned by the holder; and
•transfer to the purchase contract agent 20 Corporate Units, accompanied by a notice stating that the holder of the Corporate Units has deposited a Treasury security with the collateral agent, and requesting that the purchase contract agent instruct the collateral agent to release the related Note.
Upon receiving instructions from the purchase contract agent and receipt of the Treasury security, the collateral agent will release the related Note from the pledge and deliver it to the purchase contract agent on behalf of the holder, free and clear of our security interest. The purchase contract agent then will:
•cancel the 20 Corporate Units;
•transfer the related Note to the holder; and
•deliver 20 Treasury Units to the holder.

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The Treasury security will be substituted for the Note and will be pledged to us through the collateral agent to secure the holder’s obligation to purchase shares of our common stock under the related purchase contracts. The Note thereafter will trade and be transferable separately from the Treasury Units.
Holders who create Treasury Units will be responsible for any taxes, governmental charges or other fees or expenses (including, without limitation, fees and expenses payable to the collateral agent) attributable to such collateral substitution. See “Certain Provisions of the Purchase Contract and Pledge Agreement—Miscellaneous.”
Recreating Corporate Units
Each holder of 20 Treasury Units will have the right, at any time, other than during a blackout period or after a successful remarketing, to substitute for the related Treasury security held by the collateral agent a Note having a principal amount equal to $1,000. This substitution would recreate 20 Corporate Units and the applicable Treasury security would be released from the pledge under the purchase contract and pledge agreement and delivered to the holder and would be tradable and transferable separately from the Corporate Units. Because Treasury securities and Notes are issued in integral multiples of $1,000, holders of Treasury Units may make this substitution only in integral multiples of 20 Treasury Units. After a successful remarketing, holders may not recreate Corporate Units from Treasury Units.
To recreate 20 Corporate Units, a holder is required to:
•deposit with the collateral agent a Note having a principal amount of $1,000, which must be purchased in the open market at the expense of the Treasury Unit holder, unless otherwise owned by the holder; and
•transfer to the purchase contract agent 20 Treasury Units, accompanied by a notice stating that the holder of the Treasury Units has deposited a Note having a principal amount of $1,000 with the collateral agent and requesting that the purchase contract agent instruct the collateral agent to release the related Treasury security.
Upon receiving instructions from the purchase contract agent and receipt of the Note having a principal amount of $1,000, the collateral agent will promptly release the related Treasury security from the pledge and promptly instruct the securities intermediary to transfer such Treasury security to the purchase contract agent for distribution to the holder, free and clear of our security interest. The purchase contract agent then will:
•cancel the 20 Treasury Units;
•transfer the related Treasury security to the holder; and
•deliver 20 Corporate Units to the holder.
The $1,000 principal amount Note will be substituted for the Treasury security and will be pledged to us through the collateral agent to secure the holder’s obligation to purchase shares of our common stock under the related purchase contracts. The Treasury security thereafter will trade and be transferable separately from the Corporate Units.
Holders who recreate Corporate Units will be responsible for any taxes, governmental charges or other fees or expenses (including, without limitation, fees and expenses payable to the collateral agent)
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attributable to the collateral substitution. See “Certain Provisions of the Purchase Contract and Pledge Agreement—Miscellaneous.”
Payments on the Equity Units
Holders of Corporate Units and Treasury Units will receive quarterly contract adjustment payments payable by us at the rate of 2.725% per year on the stated amount of $50.00 per Equity Unit. We will make all contract adjustment payments on the Corporate Units and the Treasury Units quarterly in arrears on March 15, June 15, September 15 and December 15 of each year (except that if any such date is not a business day, contract adjustment payments will be payable on the following business day, without adjustment), commencing June 15, 2019. Unless the purchase contracts have been terminated (as described under “Description of the Purchase Contracts—Termination” below), we will make such contract adjustment payments until the earliest of the purchase contract settlement date, the fundamental change early settlement date (in the case of a fundamental change early settlement, as described under “Description of the Purchase Contracts—Early Settlement Upon a Fundamental Change” below) and the most recent contract adjustment payment date on or before any other early settlement with respect to the related purchase contracts (in the case of an early settlement as described under “Description of the Purchase Contracts—Early Settlement” below). If the purchase contracts have been terminated, our obligation to pay the contract adjustment payments, including any accrued and unpaid contract adjustment payments and deferred contract adjustment payments (including compounded contract adjustment payments thereon), will cease. In addition, holders of Corporate Units will receive quarterly cash distributions consisting of their pro rata share of interest payments on the Notes (or distributions on the applicable ownership interest in the Treasury portfolio, as applicable), equivalent to the rate of 3.40% per year. There will be no interest payments in respect of the Treasury securities that are a component of the Treasury Units, but to the extent that such holders of Treasury Units continue to hold the Notes that were delivered to them when they created the Treasury Units, such holders will continue to receive the scheduled interest payments on their separate Notes for as long as they hold the Notes.
We have the right to defer payment of quarterly contract adjustment payments and of interest on the Notes as described under “Description of the Purchase Contracts—Contract Adjustment Payments” and “Description of the Junior Subordinated Debentures—Option to Defer Interest Payments,” respectively.
Listing
We intend to apply to list the Corporate Units on the New York Stock Exchange and expect trading to commence within 30 days of the initial issuance of the Corporate Units under the symbol “AEPPRB.” Except in connection with early settlement, fundamental change early settlement, a termination event or settlement on the purchase contract settlement date with separate cash, unless and until substitution has been made as described in “—Creating Treasury Units by Substituting a Treasury Security for a Note” or “—Recreating Corporate Units,” neither the Note or applicable ownership interest in the Treasury portfolio component of a Corporate Unit nor the Treasury security component of a Treasury Unit will trade separately from Corporate Units or Treasury Units. The Note or applicable ownership interest in the Treasury portfolio component will trade as a unit with the purchase contract component of the Corporate Units, and the Treasury security component will trade as a unit with the purchase contract component of the Treasury Units. In addition, if Treasury Units or Notes are separately traded to a sufficient extent that the applicable exchange listing requirements are met, we may endeavor to cause the Treasury Units or Notes to be listed on the exchange on which the Corporate Units are then listed, including, if applicable, the New York Stock Exchange. However, there can be no assurance that we will list the Treasury Units or the Notes.
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Ranking
The Notes, which are included in the Equity Units, will be our junior subordinated obligations, subordinated to our existing and future Senior Indebtedness (as defined under “Description of the Junior Subordinated Debentures—Subordination”). The Notes will be issued under our subordinated indenture and the supplemental indenture (each defined under “Description of the Junior Subordinated Debentures— Ranking”).
In addition, our obligations with respect to contract adjustment payments will be subordinate in right of payment to our existing and future Senior Indebtedness (as defined under “Description of the Junior Subordinated Debentures—Subordination”).
The Notes and our obligations with respect to contract adjustments payments will be structurally subordinated to existing or future preferred stock and indebtedness, guarantees and other liabilities, including trade payables, of our subsidiaries.
Our subsidiaries are separate and distinct legal entities from us. Our subsidiaries have no obligation to pay any amounts due on the Notes or the purchase contracts or to provide us with funds to meet our respective payment obligations on the Notes or purchase contracts. Any payment of dividends, loans or advances by our subsidiaries to us could be subject to statutory or contractual restrictions and will be contingent upon the subsidiaries’ earnings and business considerations. Our right to receive any assets of any of our subsidiaries upon their bankruptcy, liquidation or similar reorganization, and therefore the right of the holders of the Notes or purchase contracts to participate in those assets, will be structurally subordinated to the claims of that subsidiary’s creditors, including trade creditors. Even if we are a creditor of any of our subsidiaries, our rights as a creditor would be subordinate to any security interest in the assets of our subsidiaries and any indebtedness of our subsidiaries senior to that held by us.
Voting and Certain Other Rights
Prior to the delivery of shares of common stock under each purchase contract, such purchase contract shall not entitle the holder of the Corporate Units or Treasury Units to any rights of a holder of shares of our common stock, including, without limitation, the right to vote or receive any dividends or other payments or distributions or to consent to or to receive notice as a shareholder or other rights in respect of our common stock.
Agreed Tax Treatment
Each beneficial owner of an Equity Unit, by acceptance of a beneficial interest therein, will be deemed to have agreed for U.S. federal, state and local income tax purposes (unless otherwise required by any taxing authority) (1) to treat itself as the owner, separately, of each of the applicable purchase contract and the related Note or the applicable ownership interests in the Treasury portfolio or Treasury security, as the case may be, (2) to treat the Note as indebtedness that is a “contingent payment debt instrument” (as that term is used in U.S. Treasury regulations section 1.1275-4), (3) to be bound by our determination of the comparable yield and payment schedule with respect to the Note, and (4) to allocate, as of the issue date, 100.00% of the purchase price paid for the Corporate Units to its ownership interest in the Note and 0.00% to each purchase contract, which will establish its initial tax basis in each purchase contract as $0.00 and the beneficial owner’s initial tax basis in each Note as $50.00. This position will be
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binding on each beneficial owner of each Equity Unit, but not on the IRS. See “Certain United States Federal Income and Estate Tax Consequences.”
Repurchase of the Equity Units
We may purchase from time to time any of the Equity Units that are then outstanding by tender, in the open market, by private agreement or otherwise, subject to compliance with applicable law, provided that any of the Equity Units repurchased by us will be cancelled.
DESCRIPTION OF THE PURCHASE CONTRACTS
The following is a summary of some of the terms of the purchase contracts. The purchase contracts will be issued pursuant to the purchase contract and pledge agreement among us, the purchase contract agent, the collateral agent, the custodial agent and the securities intermediary. The summaries of the purchase contracts and the purchase contract and pledge agreement contain a description of the material terms of the contracts but are only summaries and are not complete. This summary is subject to and is qualified by reference to all the provisions of the purchase contract and pledge agreement, the subordinated indenture (as defined under “Description of the Junior Subordinated Debentures—Ranking”), the supplemental indenture (as defined under “Description of the Junior Subordinated Debentures—Ranking”), the Notes and the form of remarketing agreement, including the definitions of certain terms used therein, forms of which have been or will be filed and incorporated by reference as an exhibit to the registration statement of which this prospectus supplement and the accompanying base prospectus form a part.
Purchase of Common Stock
Each purchase contract that is a component of a Corporate Unit or a Treasury Unit will obligate its holder to purchase, and us to issue and deliver, on March 15, 2022 (or if such day is not a business day, the following business day) (the “purchase contract settlement date”), for $50.00 in cash a number of shares of our common stock equal to the settlement rate (together with cash, if applicable, in lieu of any fractional shares of common stock in the manner described below), in each case, unless the purchase contract terminates prior to that date or is settled early at the holder’s option. The number of shares of our common stock issuable upon settlement of each purchase contract on the purchase contract settlement date (which we refer to as the “settlement rate”) will be determined as follows, subject to adjustment as described under “—Anti-dilution Adjustments” below:
(1)If the applicable market value of our common stock is equal to or greater than the “threshold appreciation price” of $99.5818, the settlement rate will be 0.5021 shares of our common stock (we refer to this settlement rate as the “minimum settlement rate”).
Accordingly, if the market price for our common stock increases between the date of this prospectus supplement and the period during which the applicable market value is measured and the applicable market value is greater than the threshold appreciation price, the aggregate market value of the shares of common stock issued upon settlement of each purchase contract will be higher than the stated amount, assuming that the market price of the common stock on the purchase contract settlement date is the same as the applicable market value of the common stock. If the applicable market value is the same as the threshold appreciation price, the aggregate market value of the shares issued upon settlement will be equal to the stated amount, assuming that the market price of the common stock on the purchase contract settlement date is the same as the applicable market value of the common stock.

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(2)If the applicable market value of our common stock is less than the threshold appreciation price but greater than the “reference price” of $82.98, which will be the closing price of our common stock on the New York Stock Exchange on the date the Equity Units are priced in this offering, the settlement rate will be a number of shares of our common stock equal to $50.00 divided by the applicable market value, rounded to the nearest ten thousandth of a share.
Accordingly, if the market price for the common stock increases between the date of this prospectus supplement and the period during which the applicable market value is measured, but the market price does not exceed the threshold appreciation price, the aggregate market value of the shares of common stock issued upon settlement of each purchase contract will be equal to the stated amount, assuming that the market price of the common stock on the purchase contract settlement date is the same as the applicable market value of the common stock.
(3)If the applicable market value of our common stock is less than or equal to the reference price of $82.98, the settlement rate will be 0.6026 shares of our common stock, which is equal to the stated amount divided by the reference price (we refer to this settlement rate as the “maximum settlement rate”).
Accordingly, if the market price for the common stock decreases between the date of this prospectus supplement and the period during which the applicable market value is measured and the market price is less than the reference price, the aggregate market value of the shares of common stock issued upon settlement of each purchase contract will be less than the stated amount, assuming that the market price on the purchase contract settlement date is the same as the applicable market value of the common stock. If the market price of the common stock is the same as the reference price, the aggregate market value of the shares will be equal to the stated amount, assuming that the market price of the common stock on the purchase contract settlement date is the same as the applicable market value of the common stock.
The threshold appreciation price is equal to $50.00 divided by the minimum settlement rate (such quotient rounded to the nearest $0.0001), which is $99.5818.
If you elect to settle your purchase contract early in the manner described under “—Early Settlement,” the number of shares of our common stock issuable upon settlement of such purchase contract will be 0.5021, the minimum settlement rate, subject to adjustment as described under “—Anti-dilution Adjustments.” If you elect to settle your purchase contract early upon a fundamental change, the number of shares of our common stock issuable upon settlement will be determined as described under “—Early Settlement Upon a Fundamental Change.” We refer to the minimum settlement rate and the maximum settlement rate as the “fixed settlement rates.”
The “applicable market value” means the average volume-weighted average price, or VWAP, of our common stock on each trading day during the 20 consecutive scheduled trading day period ending on the third scheduled trading day immediately preceding the purchase contract settlement date (the “market value averaging period”). The “VWAP” of our common stock means, for the relevant trading day, the per share VWAP on the principal exchange or quotation system on which our common stock is listed or admitted for trading as displayed under the heading Bloomberg VWAP on Bloomberg page AEP <EQUITY> AQR (or its equivalent successor if that page is not available) in respect of the period from the scheduled open of trading on the relevant trading day until the scheduled close of trading on the relevant trading day (or if such VWAP is unavailable, the market price of one share of our common stock on such trading day determined, using a volume-weighted average method, by a nationally recognized independent investment banking firm retained for this purpose by us).

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A “trading day” means, for purposes of determining a VWAP or closing price, a day (1) on which the principal exchange or quotation system on which our common stock is listed or admitted for trading is scheduled to be open for business and (2) on which there has not occurred or does not exist a market disruption event.
A “market disruption event” means any of the following events:
•any suspension of, or limitation imposed on, trading by the principal exchange or quotation system on which our common stock is listed or admitted for trading during the one-hour period prior to the close of trading for the regular trading session on such exchange or quotation system (or for purposes of determining a VWAP any period or periods prior to 1:00 p.m. New York City time aggregating one half hour or longer) and whether by reason of movements in price exceeding limits permitted by the relevant exchange or quotation system or otherwise relating to our common stock or in futures or option contracts relating to our common stock on the relevant exchange or quotation system; or
•any event (other than a failure to open or, except for purposes of determining a VWAP, a closure as described below) that disrupts or impairs the ability of market participants during the one-hour period prior to the close of trading for the regular trading session on the principal exchange or quotation system on which our common stock is listed or admitted for trading (or for purposes of determining a VWAP any period or periods prior to 1:00 p.m. New York City time aggregating one half hour or longer) in general to effect transactions in, or obtain market values for, our common stock on the relevant exchange or quotation system or futures or options contracts relating to our common stock on any relevant exchange or quotation system; or
•the failure to open of the principal exchange or quotation system on which futures or options contracts relating to our common stock are traded or, except for purposes of determining a VWAP, the closure of such exchange or quotation system prior to its respective scheduled closing time for the regular trading session on such day (without regard to after hours or other trading outside the regular trading session hours) unless such earlier closing time is announced by such exchange or quotation system at least one hour prior to the earlier of the actual closing time for the regular trading session on such day and the submission deadline for orders to be entered into such exchange or quotation system for execution at the actual closing time on such day.
If a market disruption event occurs on any scheduled trading day during the market value averaging period, we will notify investors on the calendar day on which such event occurs.
If 20 trading days for our common stock have not occurred during the market value averaging period, all remaining trading days will be deemed to occur on the third scheduled trading day immediately prior to the purchase contract settlement date and the VWAP of our common stock for each of the remaining trading days will be the VWAP of our common stock on that third scheduled trading day or, if such day is not a trading day, the closing price as of such day.
The “closing price” per share of our common stock means, on any date of determination, the closing sale price or, if no closing sale price is reported, the last reported sale price of our common stock on the principal U.S. securities exchange on which our common stock is listed, or if our common stock is not so listed on a U.S. securities exchange, the average of the last quoted bid and ask prices for our common stock in the over-the-counter market as reported by OTC Markets Group Inc. or similar organization, or, if those bid and ask prices are not available, the market value of our common stock on
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that date as determined by a nationally recognized independent investment banking firm retained by us for this purpose.
We will not issue any fractional shares of our common stock upon settlement of a purchase contract. Instead of a fractional share, the holder will receive an amount of cash equal to the percentage of a whole share represented by such fractional share multiplied by the closing price of our common stock on the trading day immediately preceding the purchase contract settlement date (or the trading day immediately preceding the relevant settlement date, in the case of early settlement). If, however, a holder surrenders for settlement at one time more than one purchase contract, then the number of shares of our common stock issuable pursuant to such purchase contracts will be computed based upon the aggregate number of purchase contracts surrendered.
Unless:
•a holder has settled early the related purchase contracts by delivery of cash to the purchase contract agent in the manner described under “—Early Settlement” or “—Early Settlement Upon a Fundamental Change;”
•a holder of Corporate Units has settled the related purchase contracts with separate cash in the manner described under “—Notice to Settle with Cash;” or
•an event described under “—Termination” has occurred;
then, on the purchase contract settlement date,
•in the case of Corporate Units where there has not been a successful optional or final remarketing, the holder will be deemed to have exercised its put right as described under “—Remarketing” (unless it shall have elected not to exercise such put right by delivering cash as described thereunder) and to have elected to apply the proceeds of the put price to satisfy in full the holder’s obligation to purchase our common stock under the related purchase contracts;
•in the case of Corporate Units where the Treasury portfolio or cash has replaced the Notes as a component of the Corporate Units following a successful optional remarketing, the portion of the proceeds of the applicable ownership interests in the Treasury portfolio when paid at maturity or an amount of cash equal to the stated amount of $50.00 per Corporate Unit will be applied to satisfy in full the holder’s obligation to purchase common stock under the related purchase contracts and any excess proceeds will be delivered to the purchase contract agent for the benefit of the holders of Corporate Units;
• in the case of Corporate Units where the Notes have been successfully remarketed during the final remarketing period, the portion of the remarketing proceeds sufficient to satisfy the holder’s obligation to purchase our common stock under the related purchase contracts will be applied to satisfy in full the holder’s obligation to purchase common stock under the related purchase contracts and any excess proceeds will be delivered to the purchase contract agent for the benefit of the holders of Corporate Units; and
•in the case of Treasury Units, the proceeds of the related Treasury securities, when paid at maturity, will be applied to satisfy in full the holder’s obligation to purchase our common stock under the related purchase contracts and any excess proceeds will be delivered to the purchase contract agent for the benefit of the holders of Treasury Units.

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The common stock will then be issued and delivered to the holder or the holder’s designee on the purchase contract settlement date. We will pay all stock transfer and similar taxes attributable to the initial issuance and delivery of the shares of our common stock pursuant to the purchase contracts, unless any such tax is due because the holder requests such shares to be issued in a name other than such holder’s name.
Prior to the settlement of a purchase contract, the shares of our common stock underlying each purchase contract will not be outstanding, and the holder of the purchase contract will not have any voting rights, rights to dividends or other distributions or other rights of a holder of our common stock by virtue of holding such purchase contract.
By purchasing a Corporate Unit or a Treasury Unit, a holder will be deemed to have, among other things:
•irrevocably appointed the purchase contract agent as its attorney-in-fact to enter into and perform the related purchase contract and the purchase contract and pledge agreement in the name of and on behalf of such holder;
•agreed to be bound by the terms and provisions of the Corporate Units or Treasury Units, as applicable, including, but not limited to, the terms of the related purchase contract and the purchase contract and pledge agreement, for so long as the holder remains a holder of Corporate Units or Treasury Units;
•consented to and agreed to be bound by the pledge of such holder’s right, title and interest in and to its undivided beneficial ownership interest in Notes, the portion of the Treasury portfolio (or cash) described in the first clause of the definition of “applicable ownership interest,” or the Treasury securities, as applicable, and the delivery of such collateral by the purchase contract agent to the collateral agent; and
•agreed to the satisfaction of the holder’s obligations under the purchase contracts with the proceeds of the pledged undivided beneficial ownership in the Notes, Treasury portfolio (or cash), Treasury securities or put price, as applicable, in the manner described above.
Remarketing
We have agreed to enter into a remarketing agreement with one or more remarketing agents, the “remarketing agent,” no later than 20 days prior to the first day of the final remarketing period or, if we elect to conduct an optional remarketing, no later than 20 days prior to the optional remarketing period.
During a blackout period that relates to each remarketing period:
•you may not settle a purchase contract early;
•you may not create Treasury Units; and
•you may not recreate Corporate Units from Treasury Units.
We refer to each of an “optional remarketing” and a “final remarketing” as a “remarketing.” In a remarketing, the Notes that are a part of Corporate Units (except, in the case of a final remarketing, where the holder has elected to settle the purchase contract through payment of separate cash) and any separate Notes whose holders have elected to participate in the remarketing, as described under “Description of the
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Junior Subordinated Debentures—Remarketing of the Notes That Are Not Included in Corporate Units,” will be remarketed.
In consultation with the remarketing agent and without the consent of any holders of Notes, we may elect (but shall not be required to elect) to remarket the Notes as fixed-rate Notes or floating-rate Notes and, in the case of floating-rate Notes, provide that the interest on the Notes will be equal to an index rate determined by the Company plus a spread determined by the remarketing agent, in consultation with the Company, in which case interest on the Notes may be calculated on the basis of a 365 day year and the actual number of days elapsed (or such other basis as is customarily used for floating-rate Notes bearing interest at a rate based on such index rate).
All such modifications shall take effect only if the remarketing is successful, without the consent of the holders, upon the earlier of the optional remarketing settlement date and the purchase contract settlement date, and will apply to all of the Notes whether or not included in the remarketing. See “Description of the Junior Subordinated Debentures—Remarketing.” If we conduct an optional remarketing that is not successful, we may change the elections described above prior to the final remarketing period.
In order to remarket the Notes, the remarketing agent, in consultation with us, may reset the interest rate on the Notes (either upward or downward), or if the Notes are remarketed as floating-rate Notes, determine the interest rate spread applicable to the Notes, in order to produce the required price in the remarketing, as discussed under “—Optional Remarketing” and “—Final Remarketing” below. The interest deferral provisions of the Notes will not apply after a successful remarketing.
We will use commercially reasonable efforts to ensure that, if required by applicable law, a registration statement, including a prospectus, with regard to the full amount of the Notes to be remarketed will be effective under the securities laws in a form that may be used by the remarketing agent in connection with the remarketing (unless a registration statement is not required under the applicable laws and regulations that are in effect at that time or unless we conduct any remarketing in accordance with an exemption under the securities laws).
We will separately pay a fee to the remarketing agent for its services as remarketing agent. Holders whose Notes are remarketed will not be responsible for the payment of any remarketing fee in connection with the remarketing.
Optional Remarketing
Unless a termination event has occurred, we may elect, at our option, to engage the remarketing agent pursuant to the terms of the remarketing agreement, to remarket the Notes over a period selected by us that begins on or after December 13, 2021 (the third business day immediately preceding the last interest payment date prior to the purchase contract settlement date) and ends any time on or before February 24, 2022 (the eighth calendar day immediately preceding the first day of the final remarketing period). We refer to this period as the “optional remarketing period,” a remarketing that occurs during the optional remarketing period as an “optional remarketing” and the date the Notes are priced in an optional remarketing as the “optional remarketing date.” In any optional remarketing, the aggregate principal amount of the Notes that are a part of Corporate Units and any separate Notes whose holders have elected to participate in the optional remarketing, as described under “Description of the Junior Subordinated Debentures—Remarketing of the Notes That Are Not Included in Corporate Units,” will be remarketed. If we elect to conduct an optional remarketing, the remarketing agent will use its commercially reasonable efforts to obtain a price for the Notes that results in proceeds of at least 100% of the aggregate of the Treasury portfolio purchase price (as defined below) and the separate Notes purchase price (as defined below). To obtain that price, the remarketing agent may, in consultation with us, reset the interest rate on
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the Notes remarketed as fixed-rate Notes, or determine the interest rate spread for the Notes remarketed as floating-rate Notes, as described under “Description of the Junior Subordinated Debentures—Interest Rate Reset.” We will request that the depository notify its participants holding Corporate Units, Treasury Units and separate Notes of our election to conduct an optional remarketing no later than five business days prior to the date we begin the optional remarketing.
Notwithstanding anything in this prospectus supplement to the contrary, we may not elect to conduct an optional remarketing if we are then deferring interest on the Notes. See “Description of the Junior Subordinated Debentures—Option to Defer Interest Payments.”
An optional remarketing on any remarketing date will be considered successful if the remarketing agent is able to remarket the Notes for a price of at least 100% of the Treasury portfolio purchase price and the separate Notes purchase price.
Following a successful optional remarketing of the Notes, on the optional remarketing settlement date (as defined below), the portion of the remarketing proceeds equal to the Treasury portfolio purchase price will, except as described below, be used to purchase the Treasury portfolio and the remaining proceeds attributable to the Notes underlying the Corporate Units will be remitted to the purchase contract agent for distribution pro rata to the holders of such Corporate Units. The portion of the proceeds attributable to the separate Notes sold in the remarketing will be remitted to the custodial agent for distribution on the optional remarketing settlement date pro rata to the holders of such separate Notes.
If we elect to conduct an optional remarketing and the remarketing is successful:
•settlement with respect to the remarketed Notes will occur on the second business day following the optional remarketing date, unless the remarketed Notes are priced after 4:30 p.m. New York time on the optional remarketing date, in which case settlement will occur on the third business day following the optional remarketing date (we refer to such settlement date as the “optional remarketing settlement date”);
•the interest rate on the Notes will be reset, or, if we remarketed the Notes as floating-rate Notes, the interest rate spread will be determined, by the remarketing agent in consultation with us on the optional remarketing date and will become effective on the optional remarketing settlement date, if applicable;
•except in the case when the Notes are remarketed as floating-rate Notes, interest on the Notes will be payable semi-annually;
•the interest deferral provisions will cease to apply to the Notes;
•the other modifications to the terms of the Notes, as described under “—Remarketing,” will become effective;
•after the optional remarketing settlement date, your Corporate Units will consist of a purchase contract and the applicable ownership interest in the Treasury portfolio (or cash), as described herein; and
•you may no longer create Treasury Units or recreate Corporate Units from Treasury Units.
If we do not elect to conduct an optional remarketing during the optional remarketing period or no optional remarketing succeeds for any reason, the Notes will continue to be a component of the
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Corporate Units or will continue to be held separately and the remarketing agent will use its commercially reasonable efforts to remarket the Notes during the final remarketing period.
For the purposes of a successful optional remarketing, “Treasury portfolio purchase price” means the lowest aggregate ask-side price quoted by a primary U.S. government securities dealer in New York City to the quotation agent selected by us between 9:00 a.m. and 4:00 p.m., New York City time, on the optional remarketing date for the purchase of the Treasury portfolio for settlement on the optional remarketing settlement date; provided that if the Treasury portfolio consists of cash, “Treasury portfolio purchase price” means the amount of such cash.
Following a successful optional remarketing, the collateral agent will purchase, at the Treasury portfolio purchase price, a Treasury portfolio consisting of:
•U.S. Treasury securities (or principal or interest strips thereof) that mature on or prior to the purchase contract settlement date in an aggregate amount at maturity equal to the principal amount of the Notes underlying the undivided beneficial ownership interests in Notes included in the Corporate Units on the optional remarketing date; and
•U.S. Treasury securities (or principal or interest strips thereof) that mature on or prior to the purchase contract settlement date in an aggregate amount equal to the aggregate interest payment (assuming no reset of the interest rate) that would have been paid to the holders of the Corporate Units on the purchase contract settlement date on the principal amount of the Notes underlying the undivided beneficial ownership interests in Notes included in the Corporate Units on the optional remarketing date.
If U.S. Treasury securities (or principal or interest strips thereof) that are to be included in the Treasury portfolio in connection with a successful optional remarketing have a yield that is less than zero, the Treasury portfolio will consist of an amount in cash equal to the aggregate principal amount at maturity of the U.S. Treasury securities described in the bullet points above. If the provisions set forth in this paragraph apply, references in this prospectus supplement to a “Treasury security” and “U.S. Treasury securities (or principal or interest strips thereof)” in connection with the Treasury portfolio will, thereafter, be deemed to be references to such amount in cash.
The applicable ownership interests in the Treasury portfolio will be substituted for the undivided beneficial ownership interests in Notes that are components of the Corporate Units and the portion of the Treasury portfolio described in the first bullet will be pledged to us through the collateral agent to secure the Corporate Unit holders’ obligation under the purchase contracts. On the purchase contract settlement date, for each Corporate Unit, $50.00 of the proceeds from the Treasury portfolio will automatically be applied to satisfy the Corporate Unit holder’s obligation to purchase common stock under the purchase contract. In addition, proceeds from the portion of the Treasury portfolio described in the second bullet, which will equal the interest payment (without reference to the reset of the interest rate) that would have been paid on the Notes that were components of the Corporate Units at the time of remarketing, will be paid on the purchase contract settlement date to the holders of the Corporate Units.
If we elect to remarket the Notes during the optional remarketing period and a successful remarketing has not occurred on or prior to February 24, 2022 (the last day of the optional remarketing period), we will cause a notice of the failed remarketing to be published no later than 9:00 a.m., New York City time, on the business day immediately following the last date of the optional remarketing period. This notice will be validly published by making a timely release to any appropriate news agency, including Bloomberg Business News and the Dow Jones News Service. We will similarly cause a notice of a successful remarketing of the Notes to be published no later than 9:00 a.m., New York City time, on the business day immediately following the date of such successful remarketing.
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On each business day during any optional remarketing period, we have the right in our sole and absolute discretion to determine whether or not an optional remarketing will be attempted. At any time and from time to time during the optional remarketing period prior to the announcement of a successful optional remarketing, we have the right to postpone any optional remarketing in our sole and absolute discretion.
Final Remarketing
Unless a termination event or a successful optional remarketing has previously occurred, we will remarket the Notes during the five business day period ending on, and including, March 10, 2022 (the third business day immediately preceding the purchase contract settlement date). We refer to this period as the “final remarketing period,” the remarketing during this period as the “final remarketing” and the date the Notes are priced in the final marketing as the “final remarketing date.” In the final remarketing, the aggregate principal amount of the Notes that are a part of Corporate Units (except where the holder has elected to settle the purchase contract through payment of separate cash) and any separate Notes whose holders have elected to participate in the final remarketing will be remarketed. The remarketing agent will use its commercially reasonable efforts to obtain a price for the Notes to be remarketed that results in proceeds of at least 100% of the principal amount of all the Notes offered in the remarketing. To obtain that price, the remarketing agent, in consultation with us, may reset the interest rate on the Notes if the Notes are remarketed as fixed-rate Notes, or determine the interest rate spread on the Notes if the Notes are remarketed as floating-rate Notes, as described under “Description of the Junior Subordinated Debentures—Interest Rate Reset.” We will request that the depository notify its participants holding Corporate Units, Treasury Units and separate Notes of the final remarketing no later than seven days prior to the first day of the final remarketing period. In such notice, we will set forth the dates of the final remarketing period, applicable procedures for holders of separate Notes to participate in the final remarketing, the applicable procedures for holders of Corporate Units to create Treasury Units and for holders of Treasury Units to recreate Corporate Units, the applicable procedures for holders of Corporate Units to settle their purchase contracts early and any other applicable procedures, including the procedures that must be followed by a holder of separate Notes in the case of a failed remarketing if a holder of separate Notes wishes to exercise its right to put its Notes to us as described below and under “Description of the Junior Subordinated Debentures—Put Option upon Failed Remarketing.” We have the right to postpone the final remarketing in our sole and absolute discretion on any day prior to the last three business days of the final remarketing period.
A remarketing during the final remarketing period will be considered successful if the remarketing agent is able to remarket the Notes for a price of at least 100% of the aggregate principal amount of all the Notes offered in the remarketing.
If the final remarketing is successful:
•settlement with respect to the remarketed Notes will occur on the purchase contract settlement date;
•the interest rate of the Notes will be reset, or, if the Notes are remarketed as floating-rate Notes, the interest rate spread will be determined, by the remarketing agent in consultation with us, and will become effective on the reset effective date, which will be the purchase contract settlement date, as described under “Description of the Junior Subordinated Debentures—Interest Rate Reset” below;
•the other modifications to the terms of the Notes, as described under “—Remarketing,” will become effective; and

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•the collateral agent will remit the portion of the proceeds equal to the total principal amount of the Notes underlying the Corporate Units to us to satisfy in full the Corporate Unit holders’ obligations to purchase common stock under the related purchase contracts, any excess proceeds attributable to Notes underlying Corporate Units that were remarketed will be remitted to the purchase contract agent for distribution pro rata to the holders of such Notes and proceeds from the final remarketing attributable to the separate Notes remarketed will be remitted to the custodial agent for distribution pro rata to the holders of the remarketed separate Notes.
Unless a termination event has occurred, a holder has effected an early settlement or a fundamental change early settlement, or there has been a successful optional remarketing, each Corporate Unit holder has the option at any time on or after the date we give notice of a final remarketing to notify the purchase contract agent at any time prior to 4:00 p.m., New York City time, on the second business day immediately prior to the first day of the final remarketing period of its intention to settle the related purchase contracts on the purchase contract settlement date with separate cash and to provide that cash on or prior to the business day immediately prior to the first day of the final remarketing period, as described under “—Notice to Settle with Cash.” The Notes of any holder of Corporate Units who has not given this notice or failed to deliver the cash will be remarketed during the final remarketing period. In addition, holders of Notes that do not underlie Corporate Units may elect to participate in the remarketing as described under “Description of the Junior Subordinated Debentures—Remarketing of Notes That Are Not Included in Corporate Units.”
If, in spite of using its commercially reasonable efforts, the remarketing agent cannot remarket the Notes during the final remarketing period at a price equal to or greater than 100% of the aggregate principal amount of the Notes offered in the remarketing, a condition precedent set forth in the remarketing agreement has not been fulfilled or a successful remarketing has not occurred for any other reason, in each case resulting in a “failed remarketing,” holders of all Notes will have the right to put their Notes to us for an amount equal to the principal amount of their Notes (the “put price”). The conditions precedent in the remarketing agreement will include, but not be limited to, the timely filing with the SEC of all material related to the remarketing required to be filed by us, the truth and correctness of certain representations and warranties made by us in the remarketing agreement, the furnishing of certain officer’s certificates to the remarketing agent, and the receipt by the remarketing agent of customary “comfort letters” from our auditors and opinions of counsel. A holder of Corporate Units will be deemed to have automatically exercised this put right with respect to the Notes underlying such Corporate Units unless the holder has provided a written notice to the purchase contract agent of its intention to settle the purchase contract with separate cash as described below under “—Notice to Settle with Cash” prior to 4:00 p.m., New York City time, on the second business day immediately prior to the purchase contract settlement date, and on or prior to the business day immediately preceding the purchase contract settlement date has delivered the $50.00 in cash per purchase contract. Settlement with separate cash may only be effected in integral multiples of 20 Corporate Units. If a holder of Corporate Units elects to settle with separate cash, upon receipt of the required cash payment, the related Notes underlying the Corporate Units will be released from the pledge under the purchase contract and pledge agreement and delivered promptly to the purchase contract agent for delivery to the holder. The holder of the Corporate Units will then receive the applicable number of shares of our common stock on the purchase contract settlement date. The cash received by the collateral agent upon this settlement with separate cash may be invested in permitted investments, as defined in the purchase contract and pledge agreement, and the portion of the proceeds equal to the aggregate purchase price of all purchase contracts of such holders will be paid to us on the purchase contract settlement date. Any excess funds received by the collateral agent in respect of any such permitted investments over the aggregate purchase price remitted to us in satisfaction of the obligations of the holders under the purchase contracts will be distributed to the purchase contract agent for ratable payment to the applicable holders who settled with separate cash. Unless a holder of Corporate Units has elected to settle the related purchase contracts with separate cash and delivered the
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separate cash on or prior to the business day immediately preceding the purchase contract settlement date, the holder will be deemed to have elected to apply the put price against the holder’s obligations to pay the aggregate purchase price for the shares of our common stock to be issued under the related purchase contracts, thereby satisfying the obligations in full, and we will deliver to the holder our common stock pursuant to the related purchase contracts.
If a successful final remarketing has not occurred on or prior to March 10, 2022 (the last day of the final remarketing period), we will cause a notice of the failed remarketing of the Notes to be published no later than 9:00 a.m., New York City time, on the business day immediately following the last date of the final remarketing period. This notice will be validly published by making a timely release to any appropriate news agency, including Bloomberg Business News and the Dow Jones News Service.
Early Settlement
Subject to the conditions described below, a holder of Corporate Units or Treasury Units may settle the related purchase contracts at any time prior to 4:00 p.m., New York City time, on the second business day immediately preceding the purchase contract settlement date, other than during a blackout period in the case of Corporate Units. An early settlement may be made only in integral multiples of 20 Corporate Units or 20 Treasury Units; however, if the Treasury portfolio has replaced the Notes as a component of the Corporate Units following a successful optional remarketing, holders of Corporate Units may settle early only in integral multiples of 40,000 Corporate Units. In order to settle purchase contracts early, a holder of Equity Units must deliver to the purchase contract agent at the corporate trust office of the purchase contract agent or its agent, in each case, in the Borough of Manhattan, The City of New York (1) a completed “Election to Settle Early” form, along with the Corporate Unit or Treasury Unit certificate, if they are in certificated form and (2) a cash payment in immediately available funds in an amount equal to:
•$50.00 times the number of purchase contracts being settled; plus
•if the early settlement date occurs during the period from the close of business on any record date next preceding any contract adjustment payment date to the opening of business on such contract adjustment payment date, an amount equal to the contract adjustment payments payable on such contract adjustment payment date, unless we have elected to defer the contract adjustment payments payable on such contract adjustment payment date.
So long as you hold Equity Units as a beneficial interest in a global security certificate deposited with the depository, procedures for early settlement will also be governed by standing arrangements between the depository and the purchase contract agent.
The early settlement right is also subject to the condition that, if required under U.S. federal securities laws, we have a registration statement under the Securities Act in effect with respect to the shares of common stock and other securities, if any, deliverable upon settlement of a purchase contract. We have agreed that, if such a registration statement is required, we will use our commercially reasonable efforts to (1) have a registration statement in effect covering those shares of common stock and other securities, if any, to be delivered in respect of the purchase contracts being settled and (2) provide a prospectus in connection therewith, in each case in a form that may be used in connection with the early settlement right (it being understood that if there is a material business transaction or development that has not yet been publicly disclosed, we will not be required to file such registration statement or provide such a prospectus, and the early settlement right will not be available, until we have publicly disclosed such transaction or development; provided that we will use commercially reasonable efforts to make such disclosure as soon as it is commercially reasonable to do so). In the event that a holder seeks to exercise its early settlement right and a registration statement is required to be effective in connection with the
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exercise of such right but no such registration statement is then effective, the holder’s exercise of such right will be void unless and until such a registration statement is effective.
Upon early settlement, except as described below in “—Early Settlement Upon a Fundamental Change,” we will sell, and the holder will be entitled to buy, the minimum settlement rate of 0.5021 shares of our common stock (or in the case of an early settlement following a reorganization event, such number of exchange property units, as described under “—Reorganization Events” below) for each purchase contract being settled (regardless of the market price of our common stock on the date of early settlement), subject to adjustment under the circumstances described under “—Anti-dilution Adjustments” below. We will cause, no later than the second business day after the applicable early settlement date, (1) the shares of our common stock to be issued and (2) the related Notes or applicable ownership interests in the Treasury portfolio or Treasury securities, as the case may be, underlying the Equity Units and securing such purchase contracts to be released from the pledge under the purchase contract and pledge agreement, and delivered to the purchase contract agent for delivery to the holder. Upon early settlement, the holder will be entitled to receive any accrued and unpaid contract adjustment payments (including any accrued and unpaid deferred contract adjustment payments and compounded contract adjustment payments thereon) to, but excluding, the contract adjustment payment date immediately preceding the early settlement date. The holder’s right to receive future contract adjustment payments will also terminate.
If the purchase contract agent receives a completed “Election to Settle Early” form (along with the Corporate Unit or Treasury Unit certificate, if they are in certificated form) and payment of $50.00 for each purchase contract being settled (and, if required, an amount equal to the contract adjustment payments payable on the next contract adjustment payment date) prior to 4:00 p.m., New York City time, on any business day and all conditions to early settlement have been satisfied, then that day will be considered the early settlement date. If the purchase contract agent receives the foregoing at or after 4:00 p.m., New York City time, on any business day or at any time on a day that is not a business day, then the next business day will be considered the early settlement date.
Early Settlement Upon a Fundamental Change
If a “fundamental change” (as defined below) occurs prior to the 30th scheduled trading day preceding the purchase contract settlement date, then, following the fundamental change, each holder of a purchase contract, subject to certain conditions described in this prospectus supplement, will have the right to accelerate and settle the purchase contract early on the fundamental change early settlement date (defined below) at the settlement rate determined as if the applicable market value were determined, for such purpose, based on the market value averaging period starting on the 23rd scheduled trading day prior to the fundamental change early settlement date and ending on the third scheduled trading day immediately preceding the fundamental change early settlement date, plus an additional make-whole amount of shares (such additional make-whole amount of shares being hereafter referred to as the “make-whole shares”). We refer to this right as the “fundamental change early settlement right.”
If 20 trading days for our common stock have not occurred during the deemed market value averaging period referred to in the preceding paragraph, all remaining trading days will be deemed to occur on the third scheduled trading day immediately prior to the fundamental change early settlement date and the VWAP of our common stock for each of the remaining trading days will be the VWAP of our common stock on that third scheduled trading day or, if such day is not a trading day, the closing price as of such day.
We will provide each of the holders with a notice of the completion of a fundamental change within four scheduled trading days after the effective date of a fundamental change. The notice will specify (1) a date (subject to postponement as described below, the “fundamental change early settlement
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date”), which will be at least 26 scheduled trading days after the date of such notice and one business day before the purchase contract settlement date, on which date we will deliver shares of our common stock to holders who exercise the fundamental change early settlement right, (2) the date by which holders must exercise the fundamental change early settlement right, which will be no earlier than the second scheduled trading day before the fundamental change early settlement date, (3) the first scheduled trading day of the deemed market value averaging period, which will be the 23rd scheduled trading day prior to the fundamental change early settlement date, the reference price, the threshold appreciation price and the fixed settlement rates, (4) the amount and kind (per share of common stock) of the cash, securities and other consideration receivable by the holder upon settlement and (5) the amount of accrued and unpaid contract adjustment payments (including any deferred contract adjustment payments and compounded contract adjustment payments thereon), if any, that will be paid upon settlement to holders exercising the fundamental change early settlement right. To exercise the fundamental change early settlement right, you must deliver to the purchase contract agent at the corporate trust office of the purchase contract agent or its agent, in each case, in the Borough of Manhattan, The City of New York, during the period beginning on the date we deliver notice that a fundamental change has occurred and ending at 4:00 p.m., New York City time, on the third scheduled trading day immediately preceding the fundamental change early settlement date (such period, subject to extension as described below, the “fundamental change exercise period”), the certificate evidencing your Corporate Units or Treasury Units if they are held in certificated form, and payment of $50.00 for each purchase contract being settled in immediately available funds.
A “fundamental change” will be deemed to have occurred if any of the following occurs:
(1)a “person” or “group” within the meaning of Section 13(d) of the Exchange Act, as in effect on the issue date of the Corporate Units, has become the direct or indirect “beneficial owner,” as defined in Rule 13d-3 under the Exchange Act, of shares of our common stock representing more than 50% of the voting power of our common stock;
(2)(A) we are involved in a consolidation with or merger into any other person, or any merger of another person into us, or any other similar transaction or series of related transactions (other than a merger, consolidation or similar transaction that does not result in the conversion or exchange of outstanding shares of our common stock), in each case, in which 90% or more of the outstanding shares of our common stock are exchanged for or converted into cash, securities or other property, greater than 10% of the value of which consists of cash, securities or other property that is not (or will not be upon or immediately following the effectiveness of such consolidation, merger or other transaction) common stock listed on the New York Stock Exchange, the NASDAQ Global Select Market or the NASDAQ Global Market (or any of their respective successors) or (B) the consummation of any sale, lease or other transfer in one transaction or a series of related transactions of all or substantially all of our consolidated assets to any person other than one of our wholly-owned subsidiaries;
(3)our common stock ceases to be listed on at least one of the New York Stock Exchange, the NASDAQ Global Select Market or the NASDAQ Global Market (or any of their respective successors) or the announcement by any of such exchanges on which our common stock is then listed or admitted for trading that our common stock will no longer be so listed or admitted for trading, unless our common stock has been accepted for listing or admitted for trading on another of such exchanges; or
(4)our shareholders approve our liquidation, dissolution or termination;

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provided that a transaction or event or series of related transactions that constitute a fundamental change pursuant to both clauses (1) and (2) above will be deemed to constitute a fundamental change solely pursuant to clause (2) of this definition of “fundamental change.”
If you exercise the fundamental change early settlement right, we will deliver to you on the fundamental change early settlement date for each purchase contract with respect to which you have elected fundamental change early settlement, a number of shares (or exchange property units, if applicable) equal to the settlement rate described above plus the additional make-whole shares. In addition, on the fundamental change early settlement date, we will pay you the amount of any accrued and unpaid contract adjustment payments (including any deferred contract adjustment payments and compounded contract adjustment payments thereon) to, but excluding, the fundamental change early settlement date, unless the date on which the fundamental change early settlement right is exercised occurs following any record date and prior to the related scheduled contract adjustment payment date, and we are not deferring the related contract adjustment payment, in which case we will instead pay all accrued and unpaid contract adjustment payments to the holder as of such record date. You will also receive on the fundamental change early settlement date the Notes or the applicable ownership interest in the Treasury portfolio or Treasury securities underlying the Corporate Units or Treasury Units, as the case may be, with respect to which you are effecting a fundamental change early settlement, which, in each case, shall have been released from the pledge under the purchase contract and pledge agreement. If you do not elect to exercise your fundamental change early settlement right, your Corporate Units or Treasury Units will remain outstanding and will be subject to normal settlement on the purchase contract settlement date.
We have agreed that, if required under the U.S. federal securities laws, we will use our commercially reasonable efforts to (1) have in effect throughout the fundamental change exercise period a registration statement covering the common stock and other securities, if any, to be delivered in respect of the purchase contracts being settled and (2) provide a prospectus in connection therewith, in each case in a form that may be used in connection with the fundamental change early settlement (it being understood that for so long as there is a material business transaction or development that has not yet been publicly disclosed (but in no event for a period longer than 90 days), we will not be required to file such registration statement or provide such a prospectus, and the fundamental change early settlement right will not be available, until we have publicly disclosed such transaction or development; provided that we will use commercially reasonable efforts to make such disclosure as soon as it is commercially reasonable to do so). In the event that a holder seeks to exercise its fundamental change early settlement right and a registration statement is required to be effective in connection with the exercise of such right but no such registration statement is then effective or a blackout period is continuing, the holder’s exercise of such right will be void unless and until such a registration statement is effective and no blackout period is continuing. The fundamental change exercise period will be extended by the number of days during such period on which no such registration statement is effective or a blackout period is continuing (provided that the fundamental change exercise period will not be extended beyond the third scheduled trading day preceding the purchase contract settlement date) and the fundamental change early settlement date will be postponed to the third scheduled trading day following the end of the fundamental change exercise period. We will provide each of the holders with a notice of any such extension and postponement at least 23 scheduled trading days prior to any such extension and postponement.
Unless the Treasury portfolio has replaced the Notes as a component of the Corporate Units as result of a successful remarketing, holders of Corporate Units may exercise the fundamental change early settlement right only in integral multiples of 20 Corporate Units. If the Treasury portfolio has replaced the Notes as a component of Corporate Units, holders of the Corporate Units may exercise the fundamental change early settlement right only in integral multiples of 40,000 Corporate Units.

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A holder of Treasury Units may exercise the fundamental change early settlement right only in integral multiples of 20 Treasury Units.
Calculation of Make-Whole Shares. The number of make-whole shares per purchase contract applicable to a fundamental change early settlement will be determined by reference to the table below, based on the date on which the fundamental change occurs or becomes effective (the “effective date”) and the “stock price” in the fundamental change, which will be:
•in the case of a fundamental change described in clause (2) above where the holders of our common stock receive only cash in the fundamental change, the cash amount paid per share of our common stock; or
•otherwise, the average of the closing prices of our common stock over the 20 trading-day period ending on the trading day immediately preceding the effective date of the fundamental change.

Stock Price on Effective Date	

Effective
Date	$30.00	$40.00	$50.00	$70.00	$82.98	$90.00	$99.58	$120.00	$140.00	$160.00	$180.00	$200.00	$220.00	$240.00	$260.00	
3/19/2019	0.1277	0.0935	0.0722	0.0334	0.0000	0.0323	0.0664	0.0405	0.0291	0.0234	0.0197	0.0169	0.0147	0.0129	0.0113	
3/15/2020	0.0848	0.0621	0.0482	0.0214	0.0000	0.0203	0.0527	0.0274	0.0190	0.0154	0.0131	0.0113	0.0098	0.0086	0.0075	
3/15/2021	0.0436	0.0319	0.0249	0.0120	0.0000	0.0096	0.0368	0.0134	0.0095	0.0079	0.0068	0.0058	0.0051	0.0045	0.0039	
3/15/2022	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	

		
The stock prices set forth in the second row of the table (i.e., the column headers) will be adjusted upon the occurrence of certain events requiring anti-dilution adjustments to the fixed settlement rates in a manner inversely proportional to the adjustments to the fixed settlement rates.
Each of the make-whole share amounts in the table will be subject to adjustment in the same manner and at the same time as the fixed settlement rates as set forth under “—Anti-dilution Adjustments.”
The exact stock price and effective date applicable to a fundamental change may not be set forth on the table, in which case:
•if the stock price is between two stock prices on the table or the effective date is between two effective dates on the table, the amount of make-whole shares will be determined by straight line interpolation between the make-whole share amounts set forth for the higher and lower stock prices and the two effective dates based on a 365-day year, as applicable;
•if the stock price is in excess of $260.00 per share (subject to adjustment in the same manner as the stock prices set forth in the second row of the table as described above), then the make-whole share amount will be zero; and
•if the stock price is less than $30.00 per share (subject to adjustment in the same manner as the stock prices set forth in the second row of the table as described above) (the “minimum stock price”), then the make-whole share amount will be determined as if the stock price equaled the minimum stock price, using straight line interpolation, as described above, if the effective date is between two effective dates on the table.
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Notice to Settle with Cash
Unless a termination event has occurred, a holder effects an early settlement or a fundamental change early settlement with respect to the underlying purchase contract, or a successful remarketing has occurred, a holder of Corporate Units may settle the related purchase contract with separate cash by delivering the Corporate Unit certificate, if in certificated form, to the purchase contract agent at the corporate trust office of the purchase contract agent or its agent, in each case, in the Borough of Manhattan, The City of New York with the completed “Notice to Settle with Cash” form at any time on or after the date we give notice of a final remarketing and prior to 4:00 p.m., New York City time on the second business day immediately preceding the first day of the final remarketing period or, if there has been a failed final remarketing, on the second business day immediately preceding the purchase contract settlement date. Holders of Corporate Units may only cash-settle Corporate Units in integral multiples of 20 Corporate Units.
The holder must also deliver to the securities intermediary the required cash payment in immediately available funds. Such payment must be delivered prior to 4:00 p.m., New York City time, on the first business day immediately preceding the final remarketing period or, if there has been a failed remarketing, on the first business day immediately preceding the purchase contract settlement date.
Upon receipt of the cash payment, the related Note will be released from the pledge arrangement and transferred to the purchase contract agent for distribution to the holder of the related Corporate Units. The holder of the Corporate Units will then receive the applicable number of shares of our common stock on the purchase contract settlement date.
If a holder of Corporate Units that has given notice of its election to settle with cash fails to deliver the cash by the applicable time and date specified above, such holder shall be deemed to have consented to the disposition of its Notes in the final remarketing, or to have exercised its put right (as described under “—Remarketing” above), in each case, as applicable.
Any cash received by the collateral agent upon cash settlement may be invested in permitted investments, as defined in the purchase contract and pledge agreement, and the portion of the proceeds equal to the aggregate purchase price of all purchase contracts of such holders will be paid to us on the purchase contract settlement date. Any excess funds received by the collateral agent in respect of permitted investments over the aggregate purchase price remitted to us in satisfaction of the obligations of the holders under the purchase contracts will be distributed to the purchase contract agent for payment to the holders who settled with cash.
Contract Adjustment Payments
Contract adjustment payments in respect of Corporate Units and Treasury Units will be fixed at a rate per year of 2.725% of the stated amount of $50.00 per purchase contract. Contract adjustment payments payable for any period will be computed on the basis of a 360-day year of twelve 30-day months. Contract adjustment payments will accrue from the date of issuance of the purchase contracts and will be payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year, commencing June 15, 2019.
Contract adjustment payments will be payable to the holders of purchase contracts as they appear on the books and records of the purchase contract agent at the close of business on the relevant record dates, which will be the 30th day of the month immediately preceding the month in which the relevant payment date falls (or, if such day is not a business day, the next preceding business day) or if the Equity Units are held in book-entry form, the “record date” will be the business day immediately preceding the applicable payment date. These distributions will be paid through the purchase contract agent, which will
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hold amounts received in respect of the contract adjustment payments for the benefit of the holders of the purchase contracts relating to the Equity Units. Subject to any applicable laws and regulations, each such payment will be made as described under “Certain Provisions of the Purchase Contract and Pledge Agreement—Book-Entry System.”
If any date on which contract adjustment payments are to be made on the purchase contracts related to the Corporate Units or Treasury Units is not a business day, then payment of the contract adjustment payments payable on that date will be made on the next succeeding day that is a business day, and no interest or payment will be paid in respect of the delay.
For the avoidance of doubt, subject to our right to defer contract adjustment payments, all record holders of purchase contracts on any record date will be entitled to receive the full contract adjustment payment due on the related contract adjustment payment date regardless of whether the holder of such purchase contract elects to settle such purchase contract early (whether at its option or in connection with a fundamental change) following such record date.
Our obligations with respect to contract adjustment payments will be subordinated and junior in right of payment to our obligations under any of our Senior Indebtedness (as defined under “Description of the Junior Subordinated Debentures—Subordination”) and will rank on parity with the Notes.
We may, at our option and upon prior written notice to the purchase contract agent, defer all or part of the contract adjustment payments, but not beyond the purchase contract settlement date (or, with respect to an early settlement upon a fundamental change, not beyond the fundamental change early settlement date or, with respect to an early settlement other than upon a fundamental change, not beyond the contract adjustment payment date immediately preceding the early settlement date).
Deferred contract adjustment payments will accrue additional contract adjustment payments at the rate equal to 6.125% per annum (which is equal to the rate of total distributions on the Corporate Units), compounded on each contract adjustment payment date, to, but excluding, the contract adjustment payment date on which such deferred contract adjustment payments are paid. We refer to additional contract adjustment payments that accrue on deferred contract adjustment payments as “compounded contract adjustment payments.” We may pay any such deferred contract adjustment payments (including compounded contract adjustment payments thereon) on any scheduled contract adjustment payment date; provided that in order to pay deferred contract adjustment payments on any scheduled contract adjustment payment date other than the purchase contract settlement date, we must deliver written notice thereof to holders of the Equity Units and the purchase contract agent on or before the relevant record date. If the purchase contracts are terminated (upon the occurrence of certain events of bankruptcy, insolvency or similar reorganization with respect to us), the right to receive contract adjustment payments and deferred contract adjustment payments (including compounded contract adjustment payments thereon) will also terminate.
If we exercise our option to defer the payment of contract adjustment payments, then, until the deferred contract adjustment payments (including compounded contract adjustment payments thereon) have been paid, we will not (1) declare or pay any dividends on, or make any distributions on, or redeem, purchase or acquire, or make a liquidation payment with respect to, any shares of our capital stock, (2) make any payment of principal of, or interest or premium, if any, on, or repay, repurchase or redeem any of our debt securities that rank on parity with, or junior to, the contract adjustment payments, or (3) make any guarantee payments under any guarantee by us of securities of any of our subsidiaries if our guarantee ranks on parity with, or junior to, the contract adjustment payments.
The restrictions listed above do not apply to:

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(a)purchases, redemptions or other acquisitions of our capital stock in connection with any employment contract, benefit plan or other similar arrangement with or for the benefit of employees, officers, directors, agents or consultants or a stock purchase or dividend reinvestment plan, or the satisfaction of our obligations pursuant to any contract or security outstanding on the date that the contract adjustment payment is deferred requiring us to purchase, redeem or acquire our capital stock;
(b)any payment, repayment, redemption, purchase, acquisition or declaration of dividends described in clause (1) above as a result of a reclassification of our capital stock, or the exchange or conversion of all or a portion of one class or series of our capital stock, for another class or series of our capital stock;
(c)the purchase of fractional interests in shares of our capital stock pursuant to the conversion or exchange provisions of our capital stock or the security being converted or exchanged, or in connection with the settlement of stock purchase contracts outstanding on the date that the contract adjustment payment is deferred;
(d)dividends or distributions paid or made in our capital stock (or rights to acquire our capital stock), or repurchases, redemptions or acquisitions of capital stock in connection with the issuance or exchange of capital stock (or of securities convertible into or exchangeable for shares of our capital stock) and distributions in connection with the settlement of stock purchase contracts outstanding on the date that the contract adjustment payment is deferred;
(e)redemptions, exchanges or repurchases of, or with respect to, any rights outstanding under a shareholder rights plan outstanding on the date that the contract adjustment payment is deferred or the declaration or payment thereunder of a dividend or distribution of or with respect to rights in the future;
(f)payments on the Notes, any trust preferred securities, subordinated debentures, junior subordinated debentures or junior subordinated notes, or any guarantees of any of the foregoing, in each case, that rank equal in right of payment to the contract adjustment payments, so long as the amount of payments made on account of such securities or guarantees and the purchase contracts is paid on all such securities and guarantees and the purchase contracts then outstanding on a pro rata basis in proportion to the full payment to which each series of such securities, guarantees or purchase contracts is then entitled if paid in full; provided that, for the avoidance of doubt, we will not be permitted under the purchase contract and pledge agreement to make contract adjustment payments in part; or
(g)any payment of deferred interest or principal on, or repayment, redemption or repurchase of, parity or junior securities that, if not made, would cause us to breach the terms of the instrument governing such parity or junior securities.
Anti-dilution Adjustments
Each fixed settlement rate will be subject to the following adjustments:
(1)Stock Dividends. If we pay or make a dividend or other distribution on our common stock in common stock, each fixed settlement rate in effect at the opening of business on the day following the date fixed for the determination of stockholders entitled to receive such dividend or other distribution will be increased by dividing:

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•each fixed settlement rate by
•a fraction, the numerator of which will be the number of shares of our common stock outstanding at the close of business on the date fixed for such determination and the denominator of which will be the sum of such number of shares and the total number of shares constituting the dividend or other distribution.
If any dividend or distribution in this paragraph (1) is declared but not so paid or made, the new fixed settlement rates shall be readjusted, on the date that our board of directors determines not to pay or make such dividend or distribution, to the fixed settlement rates that would then be in effect if such dividend or distribution had not been declared.
(2)Stock Purchase Rights. If we issue to all or substantially all holders of our common stock rights, options, warrants or other securities (other than pursuant to a dividend reinvestment, share purchase or similar plan), entitling them to subscribe for or purchase shares of our common stock for a period expiring within 45 days from the date of issuance of such rights, options, warrants or other securities at a price per share of our common stock less than the current market price (as defined below) calculated as of the date fixed for the determination of stockholders entitled to receive such rights, options, warrants or other securities, each fixed settlement rate in effect at the opening of business on the day following the date fixed for such determination will be increased by dividing:
•each fixed settlement rate by
•a fraction, the numerator of which will be the number of shares of our common stock outstanding at the close of business on the date fixed for such determination plus the number of shares of our common stock which the aggregate consideration expected to be received by us upon the exercise of such rights, options, warrants or other securities would purchase at such current market price and the denominator of which will be the number of shares of our common stock outstanding at the close of business on the date fixed for such determination plus the number of shares of our common stock so offered for subscription or purchase.
If any right, option, warrant or other security described in this paragraph (2) is not exercised or converted prior to the expiration of the exercisability or convertibility thereof (and as a result no additional shares of common stock are delivered or issued pursuant to such right, option, or warrant or other security), the new fixed settlement rates shall be readjusted, as of the date of such expiration, to the fixed settlement rates that would then be in effect had the increase with respect to the issuance of such rights, options, warrants or other securities been made on the basis of delivery or issuance of only the number of shares of common stock actually delivered.
For purposes of this clause (2), in determining whether any rights, options, warrants or other securities entitle the holders to subscribe for or purchase shares of the common stock at a price per share of our common stock less than the current market price on the date fixed for the determination of stockholders entitled to receive such rights, options, warrants or other securities, and in determining the aggregate price payable to exercise such rights, options, warrants or other securities, there shall be taken into account any consideration received by us for such rights, options, warrants or other securities and any amount payable on exercise or conversion thereof, the value of such consideration, if other than cash, to be determined in good faith by our board of directors.
(3)Stock Splits; Reverse Splits; and Combinations. If outstanding shares of our common stock shall be subdivided, split or reclassified into a greater number of shares of
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common stock, each fixed settlement rate in effect at the opening of business on the day following the day upon which such subdivision, split or reclassification becomes effective shall be proportionately increased, and, conversely, in case outstanding shares of our common stock shall each be combined or reclassified into a smaller number of shares of common stock, each fixed settlement rate in effect at the opening of business on the day following the day upon which such combination or reclassification becomes effective shall be proportionately reduced.
(4)Debt, Asset or Security Distributions. If we, by dividend or otherwise, distribute to all or substantially all holders of our common stock evidences of our indebtedness, assets or securities or any rights, options or warrants (or similar securities) to subscribe for, purchase or otherwise acquire evidences of our indebtedness, other assets or property of ours or other securities (but excluding any rights, options, warrants or other securities referred to in paragraph (2) above, any dividend or distribution paid exclusively in cash referred to in paragraph (5) below (in each case, whether or not an adjustment to the fixed settlement rates is required by such paragraph) and any dividend paid in shares of capital stock of any class or series, or similar equity interests, of or relating to a subsidiary or other business unit of ours in the case of a spin-off referred to below, or dividends or distributions referred to in paragraph (1) above), each fixed settlement rate in effect immediately prior to the close of business on the date fixed for the determination of stockholders entitled to receive such dividend or distribution shall be increased by dividing:
•each fixed settlement rate by
•a fraction, the numerator of which shall be the current market price of our common stock calculated as of the date fixed for such determination less the then fair market value (as determined in good faith by our board of directors) of the portion of the assets, securities or evidences of indebtedness so distributed applicable to one share of our common stock and the denominator of which shall be such current market price.
Notwithstanding the foregoing, if the then fair market value (as determined in good faith by our board of directors) of the portion of the assets, securities or evidences of indebtedness so distributed applicable to one share of our common stock exceeds the current market price of our common stock on the date fixed for the determination of stockholders entitled to receive such distribution, in lieu of the foregoing increase, each holder of a purchase contract shall receive, for each purchase contract, at the same time and upon the same terms as holders of shares of our common stock, the amount of such distributed assets, securities or evidences of indebtedness that such holder would have received if such holder owned a number of shares of our common stock equal to the maximum settlement rate on the record date for such dividend or distribution.
In the case of the payment of a dividend or other distribution on our common stock of shares of capital stock of any class or series, or similar equity interests, of or relating to a subsidiary or other business unit of ours, which are or will, upon issuance, be listed on a U.S. securities exchange or quotation system, which we refer to as a “spin-off,” each fixed settlement rate in effect immediately before the close of business on the date fixed for determination of stockholders entitled to receive that dividend or distribution will be increased by dividing:
•each fixed settlement rate by
•a fraction, the numerator of which is the current market price of our common stock and the denominator of which is such current market price plus the fair market value, determined as
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described below, of those shares of capital stock or similar equity interests so distributed applicable to one share of common stock.
The adjustment to the fixed settlement rate under the preceding paragraph will occur on:
•the 10th trading day from and including the effective date of the spin-off; or
•if the spin-off is effected simultaneously with an initial public offering of the securities being distributed in the spin-off and the ex-date for the spin-off occurs on or before the date that the initial public offering price of the securities being distributed in the spin-off is determined, the issue date of the securities being offered in such initial public offering.
For purposes of this section, “initial public offering” means the first time securities of the same class or type as the securities being distributed in the spin-off are offered to the public for cash.
Subject to the immediately following paragraph, the fair market value of the securities to be distributed to holders of our common stock means the average of the closing sale prices of those securities on the principal U.S. securities exchange or quotation system on which such securities are listed or quoted at that time over the first 10 trading days following the effective date of the spin-off. Also, for purposes of such a spin-off, the current market price of our common stock means the average of the closing sale prices of our common stock on the principal U.S. securities exchange or quotation system on which our common stock is listed or quoted at that time over the first 10 trading days following the effective date of the spin-off.
If, however, an initial public offering of the securities being distributed in the spin-off is to be effected simultaneously with the spin-off and the ex-date for the spin-off occurs on or before the date that the initial public offering price of the securities being distributed in the spin-off is determined, the fair market value of the securities being distributed in the spin-off means the initial public offering price, while the current market price of our common stock means the closing sale price of our common stock on the principal U.S. securities exchange or quotation system on which our common stock is listed or quoted at that time on the trading day on which the initial public offering price of the securities being distributed in the spin-off is determined.
If any dividend or distribution described in this paragraph (4) is declared but not so paid or made, the new fixed settlement rates shall be readjusted, as of the date our board of directors determines not to pay or make such dividend or distribution, to the fixed settlement rates that would then be in effect if such dividend or distribution had not been declared.
(5)Cash Distributions. If we, by dividend or otherwise, make distributions to all or substantially all holders of our common stock exclusively in cash during any quarterly period in an amount that exceeds $0.67 per share per quarter in the case of a regular quarterly dividend (such per share amount being referred to as the “reference dividend”), then immediately after the close of business on the date fixed for determination of the stockholders entitled to receive such distribution, each fixed settlement rate in effect immediately prior to the close of business on such date will be increased by dividing:
•each fixed settlement rate by
•a fraction, the numerator of which will be equal to the current market price on the date fixed for such determination less the amount, if any, by which the per share amount of the distribution exceeds the reference dividend and the denominator of which will be equal to such current market price.
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Notwithstanding the foregoing, if (1) the amount by which the per share amount of the cash distribution exceeds the reference dividend exceeds (2) the current market price of our common stock on the date fixed for the determination of stockholders entitled to receive such distribution, in lieu of the foregoing increase, each holder of a purchase contract shall receive, for each purchase contract, at the same time and upon the same terms as holders of shares of our common stock, the amount of distributed cash that such holder would have received if such holder owned a number of shares of our common stock equal to the maximum settlement rate on the record date for such cash dividend or distribution.
The reference dividend will be subject to an inversely proportional adjustment whenever each fixed settlement rate is adjusted, other than pursuant to this paragraph (5). For the avoidance of doubt, the reference dividend will be zero in the case of a cash dividend that is not a regular quarterly dividend.
If any dividend or distribution described in this paragraph (5) is declared but not so paid or made, the new fixed settlement rate shall be readjusted, as of the date our board of directors determines not to pay or make such dividend or distribution, to the fixed settlement rate that would then be in effect if such dividend or distribution had not been declared.
(6)Tender and Exchange Offers. In the case that a tender offer or exchange offer made by us or any subsidiary for all or any portion of our common stock shall expire and such tender or exchange offer (as amended through the expiration thereof) requires the payment to stockholders (based on the acceptance (up to any maximum specified in the terms of the tender offer or exchange offer) of purchased shares) of an aggregate consideration having a fair market value per share of our common stock that exceeds the closing price of our common stock on the trading day next succeeding the last date on which tenders or exchanges may be made pursuant to such tender offer or exchange offer, then, immediately prior to the opening of business on the day after the date of the last time (which we refer to as the “expiration time”) tenders or exchanges could have been made pursuant to such tender offer or exchange offer (as amended through the expiration thereof), each fixed settlement rate in effect immediately prior to the close of business on the date of the expiration time will be increased by dividing:
•each fixed settlement rate by
•a fraction (1) the numerator of which will be equal to (a) the product of (i) the current market price on the date of the expiration time and (ii) the number of shares of common stock outstanding (including any tendered or exchanged shares) on the date of the expiration time less (b) the amount of cash plus the fair market value of the aggregate consideration payable to stockholders pursuant to the tender offer or exchange offer (assuming the acceptance by us of purchased shares (as defined below)), and (2) the denominator of which will be equal to the product of (a) the current market price on the date of the expiration time and (b) the result of (i) the number of shares of our common stock outstanding (including any tendered or exchanged shares) on the date of the expiration time less (ii) the number of all shares validly tendered, not withdrawn and accepted for payment on the date of the expiration time (such actually validly tendered or exchanged shares, up to any maximum acceptance amount specified by us in the terms of the tender offer or exchange offer, being referred to as the “purchased shares”).
For purposes of paragraphs (2) through (6) (except as otherwise expressly provided therein with respect to spin-offs) above, the “current market price” per share of our common stock or any other security on any day means the average VWAP of our common stock or such other security on the principal U.S. securities exchange or quotation system on which our common stock or such other security, as applicable, is listed or quoted at that time for the 10 consecutive trading days preceding the
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earlier of the trading day preceding the day in question and the trading day before the “ex-date” with respect to the issuance or distribution requiring such computation. For purposes of paragraph (6) above, the last day of the measurement period shall be the trading day next succeeding the last date on which tenders or exchanges may be made pursuant to the relevant tender offer or exchange offer. The term “ex-date,” when used with respect to any issuance or distribution on our common stock or any other security, means the first date on which our common stock or such other security, as applicable, trades, regular way, on the principal U.S. securities exchange or quotation system on which our common stock or such other security, as applicable, is listed or quoted at that time, without the right to receive the issuance or distribution.
We currently do not have a shareholders rights plan with respect to our common stock. To the extent that we have a shareholders rights plan involving the issuance of share purchase rights or other similar rights to all or substantially all holders of our common stock in effect upon settlement of a purchase contract, you will receive, in addition to the common stock issuable upon settlement of any purchase contract, the related rights for the common stock under the shareholders rights plan, unless, prior to any settlement of a purchase contract, the rights have separated from the common stock, in which case each fixed settlement rate will be adjusted at the time of separation as if we made a distribution to all holders of our common stock as described in clause (4) above, subject to readjustment in the event of the expiration, termination or redemption of the rights under the shareholder rights plan.
You may be treated as receiving a constructive distribution from us with respect to the purchase contract if (1) the fixed settlement rates are adjusted (or fail to be adjusted) and, as a result of the adjustment (or failure to adjust), your proportionate interest in our assets or earnings and profits is increased, and (2) the adjustment (or failure to adjust) is not made pursuant to a bona fide, reasonable anti-dilution formula. For example, if the fixed settlement rate is adjusted as a result of a distribution that is taxable to the holders of our common stock, such as a cash dividend, you will be deemed to have received a “constructive distribution” of our stock. Thus, under certain circumstances, an adjustment to the fixed settlement rates might give rise to a taxable dividend to you even though you will not receive any cash in connection with such adjustment. In addition, non-U.S. holders (as defined in “Certain United States Federal Income and Estate Tax Consequences”) may, in certain circumstances, be deemed to have received a distribution subject to U.S. federal withholding tax. See “Certain United States Federal Income and Estate Tax Consequences—U.S. Holders—Purchase Contracts” and “Certain United States Federal Income and Estate Tax Consequences—Non-U.S. Holders—Dividends.”
In addition, we may increase the fixed settlement rates if our board of directors deems it advisable to avoid or diminish any income tax to holders of our common stock resulting from any dividend or distribution of shares (or rights to acquire shares) or from any event treated as a dividend or distribution for income tax purposes or for any other reasons. We may only make such a discretionary adjustment if we make the same proportionate adjustment to each fixed settlement rate.
Adjustments to the fixed settlement rates will be calculated to the nearest ten thousandth of a share. No adjustment to the fixed settlement rates will be required unless the adjustment would require an increase or decrease of at least one percent in one or both fixed settlement rates. If any adjustment is not required to be made because it would not change one or both fixed settlement rates by at least one percent, then the adjustment will be carried forward and taken into account in any subsequent adjustment. All anti-dilution adjustments will be made not later than each day of any market value averaging period and the time at which we are otherwise required to determine the relevant settlement rate or amount of make-whole shares (if applicable) in connection with any settlement with respect to the purchase contracts.
No adjustment to the fixed settlement rates will be made if holders of Equity Units participate, as a result of holding the Equity Units and without having to settle the purchase contracts that form part of
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the Equity Units, in the transaction that would otherwise give rise to an adjustment as if they held a number of shares of our common stock equal to the maximum settlement rate, at the same time and upon the same terms as the holders of common stock participate in the transaction.
The fixed settlement rates will not be adjusted (subject to our right to increase them if our board of directors deems it advisable as described in the third preceding paragraph):
•upon the issuance of any shares of our common stock pursuant to any present or future plan providing for the reinvestment of dividends or interest payable on our securities and the investment of additional optional amounts in shares of our common stock under any plan;
•upon the issuance of options, restricted stock or other awards in connection with any employment contract, executive compensation plan, benefit plan or other similar arrangement with or for the benefit of any one or more employees, officers, directors, consultants or independent contractors or the exercise of such options or other awards;
•upon the issuance of any shares of our common stock pursuant to any option, warrant, right or exercisable, exchangeable or convertible security outstanding as of the date the Equity Units were first issued;
•for a change in the par value or no par value of the common stock; or
•for accumulated and unpaid contract adjustment payments.
We will, as promptly as practicable after the fixed settlement rate is adjusted, provide written notice of the adjustment to the holders of Equity Units.
If an adjustment is made to the fixed settlement rates, an adjustment also will be made to the reference price and the threshold appreciation price on an inversely proportional basis solely to determine which of the clauses of the definition of settlement rate will be applicable to determine the settlement rate with respect to the purchase contract settlement date or any fundamental change early settlement date.
If any adjustment to the fixed settlement rates becomes effective, or any effective date, expiration time, ex-date or record date for any stock split or reverse stock split, tender or exchange offer, issuance, dividend or distribution (relating to a required fixed settlement rate adjustment) occurs, during the period beginning on, and including, (1) the open of business on a first trading day of the 20 scheduled trading-day period during which the applicable market value is calculated or (2) in the case of the optional early settlement or fundamental change early settlement, the relevant early settlement date or the date on which the fundamental change early settlement right is exercised and, in each case, ending on, and including, the date on which we deliver shares of our common stock under the related purchase contract, we will make appropriate adjustments to the fixed settlement rates and/or the number of shares of our common stock deliverable upon settlement with respect to the purchase contract, in each case, consistent with the methodology used to determine the anti-dilution adjustments set forth above. If any adjustment to the fixed settlement rates becomes effective, or any effective date, expiration time, ex-date or record date for any stock split or reverse stock split, tender or exchange offer, issuance, dividend or distribution (relating to a required fixed settlement rate adjustment) occurs, during the period used to determine the “stock price” or any other averaging period hereunder, we will make appropriate adjustments to the applicable prices, consistent with the methodology used to determine the anti-dilution adjustments set forth above.
Reorganization Events
The following events are defined as “reorganization events”:
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•any consolidation or merger of the Company with or into another person or of another person with or into the Company or a similar transaction (other than a consolidation, merger or similar transaction in which the Company is the continuing corporation and in which the shares of our common stock outstanding immediately prior to the merger or consolidation are not exchanged for cash, securities or other property of the Company or another person);
•any sale, transfer, lease or conveyance to another person of the property of the Company as an entirety or substantially as an entirety, as a result of which the shares of our common stock are exchanged for cash, securities or other property;
•any statutory exchange of the common stock of the Company with another corporation (other than in connection with a merger or acquisition); and
•any liquidation, dissolution or termination of the Company (other than as a result of or after the occurrence of a termination event described below under “—Termination”).
Following the effective date of a reorganization event, the settlement rate shall be determined by reference to the value of an exchange property unit, and we shall deliver, upon settlement of any purchase contract, a number of exchange property units equal to the number of shares of our common stock that we would otherwise be required to deliver. An “exchange property unit” is the kind and amount of common stock, other securities, other property or assets (including cash or any combination thereof) receivable in such reorganization event (without any interest thereon, and without any right to dividends or distribution thereon which have a record date that is prior to the applicable settlement date) per share of our common stock by a holder of common stock that is not a person with which we are consolidated or into which we are merged or which merged into us or to which such sale or transfer was made, as the case may be (we refer to any such person as a “constituent person”), or an affiliate of a constituent person, to the extent such reorganization event provides for different treatment of common stock held by the constituent person and/or the affiliates of the constituent person, on the one hand, and non-affiliates of a constituent person, on the other hand. In the event holders of our common stock (other than any constituent person or affiliate thereof) have the opportunity to elect the form of consideration to be received in such transaction, the exchange property unit that holders of the Corporate Units or Treasury Units are entitled to receive will be deemed to be (1) the weighted average of the types and amounts of consideration received by the holders of our common stock that affirmatively make an election or (2) if no holders of our common stock affirmatively make such an election, the types and amounts of consideration actually received by the holders of our common stock.
In the event of such a reorganization event, the person formed by such consolidation or merger or the person which acquires our assets shall execute and deliver to the purchase contract agent an agreement providing that the holder of each Equity Unit that remains outstanding after the reorganization event (if any) shall have the rights described in the preceding paragraph. Such supplemental agreement shall provide for adjustments to the amount of any securities constituting all or a portion of an exchange property unit and/or adjustments to the fixed settlement rates, which, for events subsequent to the effective date of such reorganization event, shall be as nearly equivalent as may be practicable to the adjustments provided for under “—Anti-dilution Adjustments” above. The provisions described in the preceding two paragraphs shall similarly apply to successive reorganization events.
In connection with any reorganization event, we will also adjust the reference dividend based on the number of shares of common stock comprising an exchange property unit and (if applicable) the value of any non-stock consideration comprising an exchange property unit. If an exchange property unit is composed solely of non-stock consideration, the reference dividend will be zero.
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Termination
The purchase contract and pledge agreement provides that the purchase contracts and the obligations and rights of us and of the holders of Corporate Units and Treasury Units thereunder (including the holders’ obligation and right to purchase and receive shares of our common stock and to receive accrued and unpaid contract adjustment payments, including deferred contract adjustment payments and compounded contract adjustment payments thereon) will immediately and automatically terminate upon the occurrence of a termination event (as defined below).
Upon any termination event, the Equity Units will represent the right to receive the Notes underlying the undivided beneficial interest in the Notes, applicable ownership interests in the Treasury Portfolio, or the Treasury securities, as the case may be, forming part of such Equity Units. Upon the occurrence of a termination event, we will promptly give the purchase contract agent, the collateral agent and the holders notice of such termination event and the collateral agent will release the related interests in the Notes, applicable ownership interests in the Treasury portfolio or Treasury securities, as the case may be, from the pledge arrangement and transfer such interests in the Notes, applicable ownership interests in the Treasury portfolio or Treasury securities to the purchase contract agent for distribution to the holders of Corporate Units and Treasury Units. If a holder is entitled to receive Notes in an aggregate principal amount that is not an integral multiple of $1,000, the purchase contract agent may request that we issue Notes in denominations of $50.00 and integral multiples thereof in exchange for Notes in denominations of $1,000 or integral multiples thereof. In addition, if any holder is entitled to receive, with respect to its applicable ownership interests in the Treasury portfolio or its pledged Treasury securities, any securities having a principal amount at maturity of less than $1,000, the purchase contract agent will dispose of such securities for cash and pay the cash received to the holder in lieu of such applicable ownership in the Treasury portfolio or such Treasury securities. Upon any termination event, however, such release and distribution may be subject to a delay. In the event that the Company becomes the subject of a case under the U.S. Bankruptcy Code, such delay may occur as a result of the automatic stay under the U.S. Bankruptcy Code and continue until such automatic stay has been lifted. Moreover, claims arising out of the Notes will be subject to the equitable jurisdiction and powers of the bankruptcy court.
A “termination event” means any of the following events with respect to the Company:
(1)at any time on or prior to the purchase contract settlement date, a decree or order by a court having jurisdiction in the premises shall have been entered adjudicating the Company a bankrupt or insolvent, or approving as properly filed a petition seeking reorganization arrangement, adjustment or composition of or in respect of the Company under the U.S. Bankruptcy Code or any other similar applicable federal or state law and such decree or order shall have been entered more than 90 days prior to the purchase contract settlement date and shall have continued undischarged and unstayed for a period of 90 consecutive days;
(2)at any time on or prior to the purchase contract settlement date, a decree or order of a court having jurisdiction in the premises shall have been entered for the appointment of a receiver, liquidator, trustee, assignee, sequestrator or other similar official in bankruptcy or insolvency of the Company or of all or any substantial part of the Company’s property, or for the winding up or liquidation of the Company’s affairs, and such decree or order shall have been entered more than 90 days prior to the purchase contract settlement date and shall have continued undischarged and unstayed for a period of 90 consecutive days; or
(3)at any time on or prior to the purchase contract settlement date, the Company shall institute proceedings to be adjudicated a bankrupt or insolvent, or shall consent to the institution of bankruptcy or insolvency proceedings against it, or shall file a petition or answer or
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consent seeking reorganization under the U.S. Bankruptcy Code or any other similar applicable federal or state law, or shall consent to the filing of any such petition, or shall consent to the appointment of a receiver, liquidator, trustee, assignee, sequestrator or other similar official of the Company or of all or any substantial part of the Company’s property, or shall make an assignment for the benefit of creditors, or shall admit in writing its inability to pay its debts generally as they become due.
Pledged Securities and Pledge
The undivided beneficial ownership interests in the Notes, or, following a successful optional remarketing, the applicable ownership interests in the Treasury portfolio (as described under the first bullet of the definition of “Treasury portfolio”), that are a component of the Corporate Units or, if substituted, the beneficial ownership interest in the Treasury securities that are a component of the Treasury Units, collectively, the “pledged securities,” will be pledged to the collateral agent for our benefit pursuant to the purchase contract and pledge agreement to secure your obligation to purchase shares of our common stock under the related purchase contracts. The rights of the holders of the Corporate Units and Treasury Units with respect to the pledged securities will be subject to our security interest therein. No holder of Corporate Units or Treasury Units will be permitted to withdraw the pledged securities related to such Corporate Units or Treasury Units from the pledge arrangement except:
•in the case of Corporate Units, to substitute a Treasury security for the related Note, as provided under “Description of the Equity Units—Creating Treasury Units by Substituting a Treasury Security for a Note;”
•in the case of Treasury Units, to substitute a Note for the related Treasury security, as provided under “Description of the Equity Units—Recreating Corporate Units;” and
•upon early settlement, settlement through the payment of separate cash or termination of the related purchase contracts.
Subject to our security interest and the terms of the purchase contract and pledge agreement, each holder of a Corporate Unit (unless the Treasury portfolio has replaced the Notes as a component of the Corporate Unit), will be entitled through the purchase contract agent and the collateral agent to all of the proportional rights and preferences of the related Notes (including distribution, voting, redemption, repayment and liquidation rights). Each holder of Treasury Units and each holder of Corporate Units (if the Treasury portfolio has replaced the Notes as a component of the Corporate Units), will retain beneficial ownership of the related Treasury securities or the applicable ownership interests in the Treasury portfolio, as applicable, pledged in respect of the related purchase contracts. We will have no interest in the pledged securities other than our security interest.
Except as described in “Certain Provisions of the Purchase Contract and Pledge Agreement—General,” upon receipt of distributions on the pledged securities, the collateral agent will distribute such payments to the purchase contract agent, which in turn will distribute those payments to the holders in whose names the Corporate Units or Treasury Units are registered at the close of business on the record date for the distribution.

CERTAIN PROVISIONS OF THE PURCHASE CONTRACT AND PLEDGE AGREEMENT
In this Description of the Purchase Contract and Pledge Agreement, “AEP,” “we,” “us,” “our” and the “Company” refer only to American Electric Power Company, Inc. and any successor obligor, and not to any of its subsidiaries.

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The following is a summary of some of the other terms of the purchase contract and pledge agreement. The summary contains a description of additional material terms of the agreement but is only a summary and is not complete. This summary is subject to and is qualified by reference to all the provisions of the purchase contract and pledge agreement, including the definitions of certain terms used therein, the form of which has been or will be filed and incorporated by reference as an exhibit to the registration statement of which this prospectus supplement and the accompanying base prospectus form a part.
General
Payments on the Corporate Units and Treasury Units will be payable, the purchase contracts will be settled, and transfers of the Corporate Units and Treasury Units will be registrable at, the office of the purchase contract agent or its agent, in each case, in the Borough of Manhattan, The City of New York. In addition, if the Corporate Units or Treasury Units do not remain in book-entry form, we will make payments on the Corporate Units and Treasury Units by check mailed to the address of the person entitled thereto as shown on the security register or by a wire transfer to the account designated by the holder by a prior written notice.
Shares of common stock will be delivered on the purchase contract settlement date (or earlier upon early settlement), or, if the purchase contracts have terminated, the related pledged securities will be delivered (subject to delays, including potentially as a result of the imposition of the automatic stay under the U.S. Bankruptcy Code, as described under “Description of the Purchase Contracts—Termination”) at the office of the purchase contract agent or its agent upon presentation and surrender of the applicable Corporate Unit or Treasury Unit certificate, if in certificated form.
If Corporate Units or Treasury Units are in certificated form and the holder fails to present and surrender the certificate evidencing the Corporate Units or Treasury Units to the purchase contract agent on or prior to the purchase contract settlement date, the shares of common stock issuable upon settlement with respect to the related purchase contract will be registered in the name of the purchase contract agent or its nominee. The shares, together with any distributions, will be held by the purchase contract agent as agent for the benefit of the holder until the certificate is presented and surrendered or the holder provides satisfactory evidence that the certificate has been destroyed, lost or stolen, together with any indemnity that may be required by the purchase contract agent and us.
If the purchase contracts terminate prior to the purchase contract settlement date, the related pledged securities are transferred to the purchase contract agent for distribution to the holders, and a holder fails to present and surrender the certificate evidencing the holder’s Corporate Units or Treasury Units, if in certificated form, to the purchase contract agent, the related pledged securities delivered to the purchase contract agent and payments on the pledged securities will be held by the purchase contract agent as agent for the benefit of the holder until the applicable certificate is presented, if in certificated form, or the holder provides the evidence and indemnity described above.
No service charge will be made for any registration of transfer or exchange of the Corporate Units or Treasury Units, except for any tax or other governmental charge that may be imposed in connection therewith.
The purchase contract agent will have no obligation to invest or to pay interest on any amounts it holds pending payment to any holder.

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Modification
The purchase contract and pledge agreement will contain provisions permitting us, the purchase contract agent and the collateral agent, to modify the purchase contract and pledge agreement without the consent of the holders for any of the following purposes:
•to evidence the succession of another person to our obligations;
•to add to the covenants for the benefit of holders or to surrender any of our rights or powers under the purchase contract and pledge agreement;
•to evidence and provide for the acceptance of appointment of a successor purchase contract agent or a successor collateral agent or securities intermediary;
•to make provision with respect to the rights of holders pursuant to the requirements applicable to reorganization events;
•to cure any ambiguity or to correct or supplement any provisions that may be inconsistent with any other provision in the purchase contract and pledge agreement;
•to make such other provisions in regard to matters or questions arising under the purchase contract and pledge agreement that do not materially and adversely affect the rights of any holders of Equity Units; and
•to conform the provisions of the purchase contract and pledge agreement to the description of such agreement, the Equity Units and the purchase contracts contained in the preliminary prospectus supplement for the Equity Units as supplemented and/or amended by the related pricing term sheet.
The purchase contract and pledge agreement will contain provisions allowing us, the purchase contract agent and the collateral agent, subject to certain limited exceptions, to modify the terms of the purchase contracts or the purchase contract and pledge agreement with the consent of the holders of not less than a majority of the outstanding Equity Units, with holders of Corporate Units and Treasury Units voting as a single class. However, no such modification may, without the consent of the holder of each outstanding purchase contract affected thereby:
•subject to our right to defer contract adjustment payments, change any payment date;
•impair the holders’ right to institute suit for the enforcement of a purchase contract or payment of any contract adjustment payments (including compounded contract adjustment payments);
• except as required pursuant to any anti-dilution adjustment, reduce the number of shares of our common stock purchasable under a purchase contract, increase the purchase price of the shares of our common stock on settlement of any purchase contract, change the purchase contract settlement date or change the right to early settlement or fundamental change early settlement in a manner adverse to the rights of the holders or otherwise adversely affect the holder’s rights under any purchase contract, the purchase contract and pledge agreement or remarketing agreement in any respect;

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•increase the amount or change the type of collateral required to be pledged to secure a holder’s obligations under the purchase contract and pledge agreement;
•impair the right of the holder of any purchase contract to receive distributions on the collateral, or otherwise adversely affect the holder’s rights in or to such collateral;
•reduce any contract adjustment payments or any deferred contract adjustment payments (including compounded contract adjustment payments) or change any place where, or the coin or currency in which, any contract adjustment payment is payable; or
•reduce the percentage of the outstanding purchase contracts whose holders’ consent is required for the modification, amendment or waiver of the provisions of the purchase contracts and the purchase contract and pledge agreement.
However, if any amendment or proposal would adversely affect only the Corporate Units or only the Treasury Units, then only the affected class of holders will be entitled to vote on such amendment or proposal, and such amendment or proposal will not be effective except with the consent of the holders of not less than a majority of such class or, if referred to in the seven bullets above, each holder affected thereby.
No Consent to Assumption
Each holder of a Corporate Unit or a Treasury Unit will be deemed under the terms of the purchase contract and pledge agreement, by the purchase of such Corporate Unit or Treasury Unit, to have expressly withheld any consent to the assumption under Section 365 of the U.S. Bankruptcy Code or otherwise, of the related purchase contracts by us, our receiver, liquidator or trustee or person or entity performing similar functions in the event that we become a debtor under the U.S. Bankruptcy Code or other similar state or federal law providing for reorganization or liquidation.
Consolidation, Merger and Conveyance of Assets as an Entirety
We will agree not to consolidate with or merge into any other person or convey, transfer or lease our properties and assets substantially as an entirety to any person unless (1) the person formed by such consolidation or into which we merge or the person which acquires by conveyance or transfer, or which leases, our property and assets, substantially as an entirety, is a person organized and existing under the laws of the United States, any state thereof or the District of Columbia, and expressly assumes all of our responsibilities and liabilities under the purchase contracts, the Corporate Units, the Treasury Units, the purchase contract and pledge agreement, the remarketing agreement (if any) and the indenture by one or more supplemental agreements in form satisfactory to the purchase contract agent, the collateral agent and the notes trustee, executed and delivered to the purchase contract agent, the collateral agent and the notes trustee by such corporation, and (2) we or such successor corporation, as the case may be, will not, immediately after such merger or consolidation, or such sale or conveyance, be in default in the performance of any of its obligations or covenants under such agreements.
In case of any such consolidation, merger, sale or conveyance, and upon any such assumption by the successor corporation, such successor corporation shall succeed to and be substituted for us, with the same effect as if it had been named in the purchase contracts, the Corporate Units, the Treasury Units, the purchase contract and pledge agreement and the remarketing agreement (if any) as us and (other than in the case of a lease) we shall be relieved of any further obligation under the purchase contracts, the Corporate Units, the Treasury Units, the purchase contract and pledge agreement and the remarketing agreement (if any).
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Title
We, the purchase contract agent and the collateral agent may treat the registered owner of any Corporate Units or Treasury Units as the absolute owner of the Corporate Units or Treasury Units for the purpose of making payment (subject to the record date provisions described above), settling the related purchase contracts and for all other purposes.
Replacement of Equity Unit Certificates
In the event that physical certificates have been issued, any mutilated Corporate Unit or Treasury Unit certificate will be replaced by us at the expense of the holder upon surrender of the certificate to the purchase contract agent at the corporate trust office of the purchase contract agent or its agent, in each case, in the Borough of Manhattan, The City of New York. Corporate Unit or Treasury Unit certificates that become destroyed, lost or stolen will be replaced by us at the expense of the holder upon delivery to us and the purchase contract agent of evidence of their destruction, loss or theft satisfactory to us and the purchase contract agent. In the case of a destroyed, lost or stolen Corporate Unit or Treasury Unit certificate, an indemnity satisfactory to the purchase contract agent and us may be required at the expense of the holder before a replacement certificate will be issued.
Notwithstanding the foregoing, we will not be obligated to issue any Corporate Unit or Treasury Unit certificates on or after the business day immediately preceding the purchase contract settlement date or the date on which the purchase contracts have terminated. The purchase contract and pledge agreement will provide that, in lieu of the delivery of a replacement Corporate Unit or Treasury Unit certificate, the purchase contract agent, upon delivery of the evidence and indemnity described above, will, in the case of the purchase contract settlement date, deliver the shares of common stock issuable pursuant to the purchase contracts included in the Corporate Units or Treasury Units evidenced by the certificate, or, if the purchase contracts have terminated prior to the purchase contract settlement date, transfer the pledged securities included in the Corporate Units or Treasury Units evidenced by the certificate.
Governing Law
The purchase contracts and the purchase contract and pledge agreement and the remarketing agreement will be governed by, and construed in accordance with, the laws of the State of New York.
Information Concerning the Purchase Contract Agent
The Bank of New York Mellon Trust Company, N.A. (or its successor) will be the purchase contract agent. The purchase contract agent will act as the agent for the holders of Corporate Units and Treasury Units. The purchase contract agent will not be obligated to take any discretionary action in connection with a default under the terms of the Corporate Units, the Treasury Units or the purchase contract and pledge agreement.
The purchase contract and pledge agreement will contain provisions limiting the liability of the purchase contract agent. The purchase contract and pledge agreement also will contain provisions under which the purchase contract agent may resign or be replaced. Such resignation or replacement will be effective upon the appointment of a successor.
In addition to serving as the purchase contract agent, The Bank of New York Mellon Trust Company, N.A. will serve as the “notes trustee” for the Notes. We and certain of our affiliates maintain banking relationships with The Bank of New York Mellon Trust Company, N.A. or its affiliates. The Bank of New York Mellon Trust Company, N.A. also serves as trustee under our indentures under which
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we and certain of our affiliates have issued securities. The Bank of New York Mellon Trust Company, N.A. and its affiliates have purchased, and are likely to purchase in the future, our securities and securities of our affiliates.
Information Concerning the Collateral Agent
The Bank of New York Mellon Trust Company, N.A. (or its successor) will be the collateral agent. The collateral agent will act solely as our agent and will not assume any obligation or relationship of agency or trust for or with any of the holders of the Corporate Units and the Treasury Units except for the obligations owed by a pledgee of property to the owner thereof under the purchase contract and pledge agreement and applicable law.
The purchase contract and pledge agreement will contain provisions limiting the liability of the collateral agent. The purchase contract and pledge agreement also will contain provisions under which the collateral agent may resign or be replaced. Such resignation or replacement will be effective upon the appointment of a successor.
In addition to serving as the collateral agent, The Bank of New York Mellon Trust Company, N.A. will serve as the “notes trustee” for the Notes. We and certain of our affiliates maintain banking relationships with The Bank of New York Mellon Trust Company, N.A. or its affiliates. The Bank of New York Mellon Trust Company, N.A. also serves as trustee under our indentures under which we and certain of our affiliates have issued securities. The Bank of New York Mellon Trust Company, N.A. and its affiliates have purchased, and are likely to purchase in the future, our securities and securities of our affiliates.
Miscellaneous
The purchase contract and pledge agreement will provide that we will, at all times prior to the purchase contract settlement date, reserve and keep available, free from preemptive rights, out of our authorized but unissued common stock the maximum number of shares of our common stock issuable against payment (including the maximum number of make-whole shares issuable upon a fundamental change early settlement) in respect of all purchase contracts included in the Corporate Units or Treasury Units evidenced by the outstanding certificates.
The purchase contract and pledge agreement will provide that we will pay all fees and expenses related to (1) the retention of the purchase contract agent, the collateral agent, the custodial agent and the securities intermediary and (2) any enforcement by the purchase contract agent of the rights of the holders of the Corporate Units and Treasury Units. Holders who elect to substitute the related pledged securities, thereby creating Treasury Units or recreating Corporate Units, however, will be responsible for any fees or expenses payable in connection with such substitution, as well as for any commissions, fees or other expenses incurred in acquiring the pledged securities to be substituted. We will not be responsible for any such fees or expenses. The purchase contract agent shall be under no obligation to exercise any of the rights or powers vested in it by the purchase contract and pledge agreement at the request or direction of any of the holders pursuant to the purchase contract and pledge agreement, unless such holders shall have offered to the purchase contract agent security or indemnity reasonably satisfactory to the purchase contract agent against the costs, expenses and liabilities which might be incurred by it in compliance with such request or direction.
The purchase contract and pledge agreement will also provide that any court of competent jurisdiction may in its discretion require, in any suit for the enforcement of any right or remedy under the purchase contract and pledge agreement, or in any suit against the purchase contract agent for any action taken, suffered or omitted by it as purchase contract agent, the filing by any party litigant in such suit of
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an undertaking to pay the costs of such suit, and that such court may in its discretion assess reasonable costs, including reasonable attorneys’ fees and costs against any party litigant in such suit, having due regard to the merits and good faith of the claims or defenses made by such party litigant. The foregoing shall not apply to any suit instituted by the purchase contract agent, to any suit instituted by any holder, or group of holders, holding in the aggregate more than 10% of the outstanding Equity Units, or to any suit instituted by any holder for the enforcement of any interest on any Notes owed pursuant to such holder’s applicable ownership interests in Notes or contract adjustment payments on or after the respective payment date therefor in respect of any Equity Unit held by such holder, or for enforcement of the right to purchase shares of our common stock under the purchase contracts constituting part of any Equity Unit held by such holder.
Description of 2020 Equity Units
In this Description of the Equity Units, “AEP,” “we”,” “us,” “our” and the “Company” refer only to American Electric Power Company, Inc. and any successor obligor, and not to any of its subsidiaries.
The following is a summary of some of the terms of the Equity Units. This summary, together with the summaries of the terms of the purchase contracts, the purchase contract and pledge agreement and the Notes set forth under the captions “Description of the Purchase Contracts,” “Certain Provisions of the Purchase Contract and Pledge Agreement” and “Description of the Junior Subordinated Debentures” in this prospectus supplement, contain a description of the material terms of the Equity Units, but are only summaries and are not complete. This summary is subject to and is qualified by reference to all the provisions of the purchase contract and pledge agreement, the subordinated indenture (as defined under “Description of the Junior Subordinated Debentures— Ranking”), the supplemental indenture (as defined under “Description of the Junior Subordinated Debentures—Ranking”), the Notes and the form of remarketing agreement, which has been attached as an exhibit to the purchase contract and pledge agreement, including the definitions of certain terms used therein, forms of which have been or will be filed and incorporated by reference as exhibits to the registration statement of which this prospectus supplement and the accompanying base prospectus form a part.
General
We will issue the Equity Units under the purchase contract and pledge agreement among us and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent (the “purchase contract agent”), collateral agent (the “collateral agent”), custodial agent (the “custodial agent”) and securities intermediary. The Equity Units may be either Corporate Units or Treasury Units. The Equity Units will initially consist of 15,000,000 Corporate Units (or 17,000,000 Corporate Units if the underwriters exercise their option to purchase additional Corporate Units in full), each with a stated amount of $50.00.
Each Corporate Unit offered will consist of:
•a purchase contract under which
•the holder will agree to purchase from us, and we will agree to sell to the holder, on August 15, 2023 (or if such day is not a business day, the following business day), which we refer to as the “purchase contract settlement date,” or earlier upon
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early settlement, for $50.00, a number of shares of our common stock equal to the applicable settlement rate described under “Description of the Purchase Contracts—Purchase of Common Stock,” “Description of the Purchase Contracts—Early Settlement” or “Description of the Purchase Contracts—Early Settlement Upon a Fundamental Change,” as the case may be, plus, in the case of an early settlement upon a fundamental change, the number of make-whole shares; and
•we will pay the holder quarterly contract adjustment payments at the rate of 4.825% per year on the stated amount of $50.00, or $2.4125 per year, subject to our right to defer such contract adjustment payments as described under “Description of the Purchase Contracts—Contract Adjustment Payments,” and
either:
•a 1/20 undivided beneficial ownership interest in a $1,000 principal amount 1.30% junior subordinated debenture due 2025 issued by us, and under which we will pay to the holder 1/20 of the interest payment on a $1,000 principal amount Note at the initial rate of 1.30%, or $13.00 per year per $1,000 principal amount of Notes, subject to our right to defer such interest payments as described under “Description of the Junior Subordinated Debentures—Option to Defer Interest Payments;” or
•following a successful optional remarketing, the applicable ownership interest in a portfolio of U.S. Treasury securities, which we refer to as the “Treasury portfolio.”
“Applicable ownership interest” means, with respect to the Treasury portfolio,
(1)a 1/20 undivided beneficial ownership interest in $1,000 face amount of U.S. Treasury securities (or principal or interest strips thereof) included in the Treasury portfolio that mature on or prior to the purchase contract settlement date; and
(2)for the scheduled interest payment occurring on the purchase contract settlement date, a 0.01625% undivided beneficial ownership interest in $1,000 face amount of U.S. Treasury securities (or principal or interest strips thereof) that mature on or prior to the purchase contract settlement date.
If U.S. Treasury securities (or principal or interest strips thereof) that are to be included in the Treasury portfolio in connection with a successful optional remarketing have a yield that is less than zero, the Treasury portfolio will consist of an amount in cash equal to the aggregate principal amount at maturity of the U.S. Treasury securities described in clauses (1) and (2) above. If the provisions set forth in this paragraph apply, references to “Treasury security” and “U.S. Treasury securities (or principal or interest strips thereof)” in connection with the Treasury portfolio will, thereafter, be deemed to be references to such amount of cash.
So long as the Equity Units are in the form of Corporate Units, the related undivided beneficial ownership interest in the Note or the applicable ownership interest in the Treasury portfolio described in clause (1) of the definition of “applicable ownership interest” above (or $50.00 in cash, if the immediately preceding paragraph applies), as the case may be, will be
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pledged to us through the collateral agent to secure the holders’ obligations to purchase our common stock under the related purchase contracts.
Creating Treasury Units by Substituting a Treasury Security for a Note
Each holder of 20 Corporate Units may create, at any time other than after a successful remarketing or during a blackout period (as defined below), 20 Treasury Units by substituting for a Note a zero-coupon U.S. Treasury security (for example, CUSIP No. 912821ET8) with a principal amount at maturity equal to $1,000 and maturing on July 15, 2023, which we refer to as a “Treasury security.” This substitution would create 20 Treasury Units and the Note would be released from the pledge under the purchase contract and pledge agreement and delivered to the holder and would be tradable and transferable separately from the Treasury Units. Because Treasury securities and Notes are issued in integral multiples of $1,000, holders of Corporate Units may make the substitution only in integral multiples of 20 Corporate Units. After a successful remarketing, holders may not create Treasury Units from Corporate Units or recreate Corporate Units from Treasury Units.
Each Treasury Unit will consist of:
•a purchase contract under which
•the holder will agree to purchase from us, and we will agree to sell to the holder, on the purchase contract settlement date, or earlier upon early settlement, for $50.00, a number of shares of our common stock equal to the applicable settlement rate, plus, in the case of an early settlement upon a fundamental change, the number of make-whole shares; and
•we will pay the holder quarterly contract adjustment payments at the rate of 4.825% per year on the stated amount of $50.00, or $2.4125 per year, subject to our right to defer the contract adjustment payments; and
•a 1/20 undivided beneficial ownership interest in a Treasury security.
The term “blackout period” means the period (1) if we elect to conduct an optional remarketing, from 4:00 p.m., New York City time, on the second business day (as defined below) immediately preceding the first day of the optional remarking period until the settlement date of such optional remarketing or the date we announce that such remarketing was unsuccessful and (2) after 4:00 p.m., New York City time, on the second business day immediately preceding the first day of the final remarketing period.
The term “business day” means any day that is not a Saturday or Sunday or a day on which banking institutions in The City of New York are authorized or required by law or executive order to close.
The Treasury Unit holder’s beneficial ownership interest in the Treasury security will be pledged to us through the collateral agent to secure the holder’s obligation to purchase our common stock under the related purchase contracts.

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To create 20 Treasury Units, a holder is required to:
•deposit with the collateral agent a Treasury security that has a principal amount at maturity of $1,000, which must be purchased in the open market at the expense of the Corporate Unit holder, unless otherwise owned by the holder; and
•transfer to the purchase contract agent 20 Corporate Units, accompanied by a notice stating that the holder of the Corporate Units has deposited a Treasury security with the collateral agent, and requesting that the purchase contract agent instruct the collateral agent to release the related Note.
Upon receiving instructions from the purchase contract agent and receipt of the Treasury security, the collateral agent will release the related Note from the pledge and deliver it to the purchase contract agent on behalf of the holder, free and clear of our security interest. The purchase contract agent then will:
•cancel the 20 Corporate Units;
•transfer the related Note to the holder; and
•deliver 20 Treasury Units to the holder.
The Treasury security will be substituted for the Note and will be pledged to us through the collateral agent to secure the holder’s obligation to purchase shares of our common stock under the related purchase contracts. The Note thereafter will trade and be transferable separately from the Treasury Units.
Holders who create Treasury Units will be responsible for any taxes, governmental charges or other fees or expenses (including, without limitation, fees and expenses payable to the collateral agent) attributable to such collateral substitution. See “Certain Provisions of the Purchase Contract and Pledge Agreement—Miscellaneous.”
Recreating Corporate Units
Each holder of 20 Treasury Units will have the right, at any time, other than during a blackout period or after a successful remarketing, to substitute for the related Treasury security held by the collateral agent a Note having a principal amount equal to $1,000. This substitution would recreate 20 Corporate Units and the applicable Treasury security would be released from the pledge under the purchase contract and pledge agreement and delivered to the holder and would be tradable and transferable separately from the Corporate Units. Because Treasury securities and Notes are issued in integral multiples of $1,000, holders of Treasury Units may make this substitution only in integral multiples of 20 Treasury Units. After a successful remarketing, holders may not recreate Corporate Units from Treasury Units.
To recreate 20 Corporate Units, a holder is required to:

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•deposit with the collateral agent a Note having a principal amount of $1,000, which must be purchased in the open market at the expense of the Treasury Unit holder, unless otherwise owned by the holder; and
•transfer to the purchase contract agent 20 Treasury Units, accompanied by a notice stating that the holder of the Treasury Units has deposited a Note having a principal amount of $1,000 with the collateral agent and requesting that the purchase contract agent instruct the collateral agent to release the related Treasury security.
Upon receiving instructions from the purchase contract agent and receipt of the Note having a principal amount of $1,000, the collateral agent will promptly release the related Treasury security from the pledge and promptly instruct the securities intermediary to transfer such Treasury security to the purchase contract agent for distribution to the holder, free and clear of our security interest. The purchase contract agent then will:
•cancel the 20 Treasury Units;
•transfer the related Treasury security to the holder; and
•deliver 20 Corporate Units to the holder.
The $1,000 principal amount Note will be substituted for the Treasury security and will be pledged to us through the collateral agent to secure the holder’s obligation to purchase shares of our common stock under the related purchase contracts. The Treasury security thereafter will trade and be transferable separately from the Corporate Units.
Holders who recreate Corporate Units will be responsible for any taxes, governmental charges or other fees or expenses (including, without limitation, fees and expenses payable to the collateral agent) attributable to the collateral substitution. See “Certain Provisions of the Purchase Contract and Pledge Agreement—Miscellaneous.”
Payments on the Equity Units
Holders of Corporate Units and Treasury Units will receive quarterly contract adjustment payments payable by us at the rate of 4.825% per year on the stated amount of $50.00 per Equity Unit. We will make all contract adjustment payments on the Corporate Units and the Treasury Units quarterly in arrears on February 15, May 15, August 15 and November 15 of each year (except that if any such date is not a business day, contract adjustment payments will be payable on the following business day, without adjustment), commencing November 15, 2020. Unless the purchase contracts have been terminated (as described under “Description of the Purchase Contracts—Termination” below), we will make such contract adjustment payments until the earliest of the purchase contract settlement date, the fundamental change early settlement date (in the case of a fundamental change early settlement, as described under “Description of the Purchase Contracts—Early Settlement Upon a Fundamental Change” below) and the most recent contract adjustment payment date on or before any other early settlement with respect to the related purchase contracts (in the case of an early settlement as described under “Description of the Purchase Contracts—Early Settlement” below). If the purchase contracts have been terminated, our obligation to pay the contract adjustment payments, including any accrued and unpaid contract
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adjustment payments and deferred contract adjustment payments (including compounded contract adjustment payments thereon), will cease. In addition, holders of Corporate Units will receive quarterly cash distributions consisting of their pro rata share of interest payments on the Notes (or distributions on the applicable ownership interest in the Treasury portfolio, as applicable), equivalent to the rate of 1.30% per year. There will be no interest payments in respect of the Treasury securities that are a component of the Treasury Units, but to the extent that such holders of Treasury Units continue to hold the Notes that were delivered to them when they created the Treasury Units, such holders will continue to receive the scheduled interest payments on their separate Notes for as long as they hold the Notes.
We have the right to defer payment of quarterly contract adjustment payments and of interest on the Notes as described under “Description of the Purchase Contracts—Contract Adjustment Payments” and “Description of the Junior Subordinated Debentures—Option to Defer Interest Payments,” respectively.
Listing
We intend to apply to list the Corporate Units on the New York Stock Exchange and expect trading to commence within 30 days of the initial issuance of the Corporate Units under the symbol “AEPPRC.” Except in connection with early settlement, fundamental change early settlement, a termination event or settlement on the purchase contract settlement date with separate cash, unless and until substitution has been made as described in “—Creating Treasury Units by Substituting a Treasury Security for a Note” or “—Recreating Corporate Units,” neither the Note or applicable ownership interest in the Treasury portfolio component of a Corporate Unit nor the Treasury security component of a Treasury Unit will trade separately from Corporate Units or Treasury Units. The Note or applicable ownership interest in the Treasury portfolio component will trade as a unit with the purchase contract component of the Corporate Units, and the Treasury security component will trade as a unit with the purchase contract component of the Treasury Units. In addition, if Treasury Units or Notes are separately traded to a sufficient extent that the applicable exchange listing requirements are met, we may endeavor to cause the Treasury Units or Notes to be listed on the exchange on which the Corporate Units are then listed, including, if applicable, the New York Stock Exchange. However, there can be no assurance that we will list the Treasury Units or the Notes.
Ranking
The Notes, which are included in the Equity Units, will be our junior subordinated obligations, subordinated to our existing and future Senior Indebtedness (as defined under “Description of the Junior Subordinated Debentures—Subordination”). The Notes will be issued under our subordinated indenture and the supplemental indenture (each defined under “Description of the Junior Subordinated Debentures— Ranking”).
In addition, our obligations with respect to contract adjustment payments will be subordinate in right of payment to our existing and future Senior Indebtedness (as defined under “Description of the Junior Subordinated Debentures—Subordination”).

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The Notes and our obligations with respect to contract adjustments payments will be structurally subordinated to existing or future preferred stock and indebtedness, guarantees and other liabilities, including trade payables, of our subsidiaries.
Our subsidiaries are separate and distinct legal entities from us. Our subsidiaries have no obligation to pay any amounts due on the Notes or the purchase contracts or to provide us with funds to meet our respective payment obligations on the Notes or purchase contracts. Any payment of dividends, loans or advances by our subsidiaries to us could be subject to statutory or contractual restrictions and will be contingent upon the subsidiaries’ earnings and business considerations. Our right to receive any assets of any of our subsidiaries upon their bankruptcy, liquidation or similar reorganization, and therefore the right of the holders of the Notes or purchase contracts to participate in those assets, will be structurally subordinated to the claims of that subsidiary’s creditors, including trade creditors. Even if we are a creditor of any of our subsidiaries, our rights as a creditor would be subordinate to any security interest in the assets of our subsidiaries and any indebtedness of our subsidiaries senior to that held by us.
Voting and Certain Other Rights
Prior to the delivery of shares of common stock under each purchase contract, such purchase contract shall not entitle the holder of the Corporate Units or Treasury Units to any rights of a holder of shares of our common stock, including, without limitation, the right to vote or receive any dividends or other payments or distributions or to consent to or to receive notice as a shareholder or other rights in respect of our common stock.
Agreed Tax Treatment
•    Each beneficial owner of an Equity Unit, by acceptance of a beneficial interest therein, will be deemed to have agreed for U.S. federal, state and local income tax purposes (unless otherwise required by any taxing authority) (1) to treat itself as the owner, separately, of each of the applicable purchase contract and the related Note or the applicable ownership interests in the Treasury portfolio or Treasury security, as the case may be, (2) to treat the Note as indebtedness that is a “contingent payment debt instrument” (as that term is used in U.S. Treasury regulations section 1.1275-4), (3) to be bound by our determination of the comparable yield and payment schedule with respect to the Note, and’ (4) to allocate, as of the issue date, 100.00% of the purchase price paid for the Corporate Units to its ownership interest in the Note and 0.00% to each purchase contract, which will establish its initial tax basis in each purchase contract as $0.00 and the beneficial owner’s initial tax basis in each Note as $50.00. This position will be binding on each beneficial owner of each Equity Unit, but not on the IRS. See “Certain United States Federal Income and Estate Tax Consequences.”
•Repurchase of the Equity Units
We may purchase from time to time any of the Equity Units that are then outstanding by tender, in the open market, by private agreement or otherwise, subject to compliance with applicable law, provided that any of the Equity Units repurchased by us will be cancelled.

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DESCRIPTION OF THE PURCHASE CONTRACTS
The following is a summary of some of the terms of the purchase contracts. The purchase contracts will be issued pursuant to the purchase contract and pledge agreement among us, the purchase contract agent, the collateral agent, the custodial agent and the securities intermediary. The summaries of the purchase contracts and the purchase contract and pledge agreement contain a description of the material terms of the contracts but are only summaries and are not complete. This summary is subject to and is qualified by reference to all the provisions of the purchase contract and pledge agreement, the subordinated indenture (as defined under “Description of the Junior Subordinated Debentures—Ranking”), the supplemental indenture (as defined under “Description of the Junior Subordinated Debentures—Ranking”), the Notes and the form of remarketing agreement, including the definitions of certain terms used therein, forms of which have been or will be filed and incorporated by reference as an exhibit to the registration statement of which this prospectus supplement and the accompanying base prospectus form a part.
Purchase of Common Stock
Each purchase contract that is a component of a Corporate Unit or a Treasury Unit will obligate its holder to purchase, and us to issue and deliver, on August 15, 2023 (or if such day is not a business day, the following business day) (the “purchase contract settlement date”), for $50.00 in cash a number of shares of our common stock equal to the settlement rate (together with cash, if applicable, in lieu of any fractional shares of common stock in the manner described below), in each case, unless the purchase contract terminates prior to that date or is settled early at the holder’s option. The number of shares of our common stock issuable upon settlement of each purchase contract on the purchase contract settlement date (which we refer to as the “settlement rate”) will be determined as follows, subject to adjustment as described under “—Anti-dilution Adjustments” below:
(1)If the applicable market value of our common stock is equal to or greater than the “threshold appreciation price” of $99.95, the settlement rate will be 0.5003 shares of our common stock (we refer to this settlement rate as the “minimum settlement rate”).
Accordingly, if the market price for our common stock increases between the date of this prospectus supplement and the period during which the applicable market value is measured and the applicable market value is greater than the threshold appreciation price, the aggregate market value of the shares of common stock issued upon settlement of each purchase contract will be higher than the stated amount, assuming that the market price of the common stock on the purchase contract settlement date is the same as the applicable market value of the common stock. If the applicable market value is the same as the threshold appreciation price, the aggregate market value of the shares issued upon settlement will be equal to the stated amount, assuming that the market price of the common stock on the purchase contract settlement date is the same as the applicable market value of the common stock.
(2)If the applicable market value of our common stock is less than the threshold appreciation price but greater than the “reference price” of $83.29, which was the closing price of our common stock on the New York Stock Exchange on the date the Equity Units were priced in this offering, the settlement rate will be a number of shares of our common
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stock equal to $50.00 divided by the applicable market value, rounded to the nearest ten thousandth of a share.
Accordingly, if the market price for the common stock increases between the date of this prospectus supplement and the period during which the applicable market value is measured, but the market price does not exceed the threshold appreciation price, the aggregate market value of the shares of common stock issued upon settlement of each purchase contract will be equal to the stated amount, assuming that the market price of the common stock on the purchase contract settlement date is the same as the applicable market value of the common stock.
(3)If the applicable market value of our common stock is less than or equal to the reference price of $83.29, the settlement rate will be 0.6003 shares of our common stock, which is equal to the stated amount divided by the reference price (we refer to this settlement rate as the “maximum settlement rate”).
Accordingly, if the market price for the common stock decreases between the date of this prospectus supplement and the period during which the applicable market value is measured and the market price is less than the reference price, the aggregate market value of the shares of common stock issued upon settlement of each purchase contract will be less than the stated amount, assuming that the market price on the purchase contract settlement date is the same as the applicable market value of the common stock. If the market price of the common stock is the same as the reference price, the aggregate market value of the shares will be equal to the stated amount, assuming that the market price of the common stock on the purchase contract settlement date is the same as the applicable market value of the common stock.
The threshold appreciation price is equal to $50.00 divided by the minimum settlement rate (such quotient rounded to the nearest $0.0001), which is $99.95.
If you elect to settle your purchase contract early in the manner described under “—Early Settlement,” the number of shares of our common stock issuable upon settlement of such purchase contract will be 0.5003, the minimum settlement rate, subject to adjustment as described under “—Anti-dilution Adjustments.” If you elect to settle your purchase contract early upon a fundamental change, the number of shares of our common stock issuable upon settlement will be determined as described under “—Early Settlement Upon a Fundamental Change.” We refer to the minimum settlement rate and the maximum settlement rate as the “fixed settlement rates.”
The “applicable market value” means the average volume-weighted average price, or VWAP, of our common stock on each trading day during the 20 consecutive scheduled trading day period ending on the third scheduled trading day immediately preceding the purchase contract settlement date (the “market value averaging period”). The “VWAP” of our common stock means, for the relevant trading day, the per share VWAP on the principal exchange or quotation system on which our common stock is listed or admitted for trading as displayed under the heading Bloomberg VWAP on Bloomberg page AEP <EQUITY> AQR (or its equivalent successor if that page is not available) in respect of the period from the scheduled open of trading on the relevant trading day until the scheduled close of trading on the relevant trading day (or if such VWAP is unavailable, the market price of one share of our common stock on such trading day determined,
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using a volume-weighted average method, by a nationally recognized independent investment banking firm retained for this purpose by us).
A “trading day” means, for purposes of determining a VWAP or closing price, a day (1) on which the principal exchange or quotation system on which our common stock is listed or admitted for trading is scheduled to be open for business and (2) on which there has not occurred or does not exist a market disruption event.
A “market disruption event” means any of the following events:
•any suspension of, or limitation imposed on, trading by the principal exchange or quotation system on which our common stock is listed or admitted for trading during the one-hour period prior to the close of trading for the regular trading session on such exchange or quotation system (or for purposes of determining a VWAP any period or periods prior to 1:00 p.m. New York City time aggregating one half hour or longer) and whether by reason of movements in price exceeding limits permitted by the relevant exchange or quotation system or otherwise relating to our common stock or in futures or option contracts relating to our common stock on the relevant exchange or quotation system; or
•any event (other than a failure to open or, except for purposes of determining a VWAP, a closure as described below) that disrupts or impairs the ability of market participants during the one-hour period prior to the close of trading for the regular trading session on the principal exchange or quotation system on which our common stock is listed or admitted for trading (or for purposes of determining a VWAP any period or periods prior to 1:00 p.m. New York City time aggregating one half hour or longer) in general to effect transactions in, or obtain market values for, our common stock on the relevant exchange or quotation system or futures or options contracts relating to our common stock on any relevant exchange or quotation system; or
•the failure to open of the principal exchange or quotation system on which futures or options contracts relating to our common stock are traded or, except for purposes of determining a VWAP, the closure of such exchange or quotation system prior to its respective scheduled closing time for the regular trading session on such day (without regard to after hours or other trading outside the regular trading session hours) unless such earlier closing time is announced by such exchange or quotation system at least one hour prior to the earlier of the actual closing time for the regular trading session on such day and the submission deadline for orders to be entered into such exchange or quotation system for execution at the actual closing time on such day.
If a market disruption event occurs on any scheduled trading day during the market value averaging period, we will notify investors on the calendar day on which such event occurs.
If 20 trading days for our common stock have not occurred during the market value averaging period, all remaining trading days will be deemed to occur on the third scheduled trading day immediately prior to the purchase contract settlement date and the VWAP of our common stock for each of the remaining trading days will be the VWAP of our common stock on that third scheduled trading day or, if such day is not a trading day, the closing price as of such day.
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The “closing price” per share of our common stock means, on any date of determination, the closing sale price or, if no closing sale price is reported, the last reported sale price of our common stock on the principal U.S. securities exchange on which our common stock is listed, or if our common stock is not so listed on a U.S. securities exchange, the average of the last quoted bid and ask prices for our common stock in the over-the-counter market as reported by OTC Markets Group Inc. or similar organization, or, if those bid and ask prices are not available, the market value of our common stock on that date as determined by a nationally recognized independent investment banking firm retained by us for this purpose.
We will not issue any fractional shares of our common stock upon settlement of a purchase contract. Instead of a fractional share, the holder will receive an amount of cash equal to the percentage of a whole share represented by such fractional share multiplied by the closing price of our common stock on the trading day immediately preceding the purchase contract settlement date (or the trading day immediately preceding the relevant settlement date, in the case of early settlement). If, however, a holder surrenders for settlement at one time more than one purchase contract, then the number of shares of our common stock issuable pursuant to such purchase contracts will be computed based upon the aggregate number of purchase contracts surrendered.
Unless:
•a holder has settled early the related purchase contracts by delivery of cash to the purchase contract agent in the manner described under “—Early Settlement” or “—Early Settlement Upon a Fundamental Change;”
• a holder of Corporate Units has settled the related purchase contracts with separate cash in the manner described under “—Notice to Settle with Cash;” or
•an event described under “—Termination” has occurred;
then, on the purchase contract settlement date,
•in the case of Corporate Units where there has not been a successful optional or final remarketing, the holder will be deemed to have exercised its put right as described under “—Remarketing” (unless it shall have elected not to exercise such put right by delivering cash as described thereunder) and to have elected to apply the proceeds of the put price to satisfy in full the holder’s obligation to purchase our common stock under the related purchase contracts;
•in the case of Corporate Units where the Treasury portfolio or cash has replaced the Notes as a component of the Corporate Units following a successful optional remarketing, the portion of the proceeds of the applicable ownership interests in the Treasury portfolio when paid at maturity or an amount of cash equal to the stated amount of $50.00 per Corporate Unit will be applied to satisfy in full the holder’s obligation to purchase common stock under the related purchase contracts and any excess proceeds will be delivered to the purchase contract agent for the benefit of the holders of Corporate Units;

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• in the case of Corporate Units where the Notes have been successfully remarketed during the final remarketing period, the portion of the remarketing proceeds sufficient to satisfy the holder’s obligation to purchase our common stock under the related purchase contracts will be applied to satisfy in full the holder’s obligation to purchase common stock under the related purchase contracts and any excess proceeds will be delivered to the purchase contract agent for the benefit of the holders of Corporate Units; and
•in the case of Treasury Units, the proceeds of the related Treasury securities, when paid at maturity, will be applied to satisfy in full the holder’s obligation to purchase our common stock under the related purchase contracts and any excess proceeds will be delivered to the purchase contract agent for the benefit of the holders of Treasury Units.
The common stock will then be issued and delivered to the holder or the holder’s designee on the purchase contract settlement date. We will pay all stock transfer and similar taxes attributable to the initial issuance and delivery of the shares of our common stock pursuant to the purchase contracts, unless any such tax is due because the holder requests such shares to be issued in a name other than such holder’s name.
Prior to the settlement of a purchase contract, the shares of our common stock underlying each purchase contract will not be outstanding, and the holder of the purchase contract will not have any voting rights, rights to dividends or other distributions or other rights of a holder of our common stock by virtue of holding such purchase contract.
By purchasing a Corporate Unit or a Treasury Unit, a holder will be deemed to have, among other things:
•irrevocably appointed the purchase contract agent as its attorney-in-fact to enter into and perform the related purchase contract and the purchase contract and pledge agreement in the name of and on behalf of such holder;
•agreed to be bound by the terms and provisions of the Corporate Units or Treasury Units, as applicable, including, but not limited to, the terms of the related purchase contract and the purchase contract and pledge agreement, for so long as the holder remains a holder of Corporate Units or Treasury Units;
•consented to and agreed to be bound by the pledge of such holder’s right, title and interest in and to its undivided beneficial ownership interest in Notes, the portion of the Treasury portfolio (or cash) described in the first clause of the definition of “applicable ownership interest,” or the Treasury securities, as applicable, and the delivery of such collateral by the purchase contract agent to the collateral agent; and
•agreed to the satisfaction of the holder’s obligations under the purchase contracts with the proceeds of the pledged undivided beneficial ownership in the Notes, Treasury portfolio (or cash), Treasury securities or put price, as applicable, in the manner described above.
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Remarketing
We have agreed to enter into a remarketing agreement with one or more remarketing agents, the “remarketing agent,” no later than 20 days prior to the first day of the final remarketing period or, if we elect to conduct an optional remarketing, no later than 20 days prior to the optional remarketing period.
During a blackout period that relates to each remarketing period:
•you may not settle a purchase contract early;
•you may not create Treasury Units; and
•you may not recreate Corporate Units from Treasury Units.
We refer to each of an “optional remarketing” and a “final remarketing” as a “remarketing.” In a remarketing, the Notes that are a part of Corporate Units (except, in the case of a final remarketing, where the holder has elected to settle the purchase contract through payment of separate cash) and any separate Notes whose holders have elected to participate in the remarketing, as described under “Description of the Junior Subordinated Debentures—Remarketing of the Notes That Are Not Included in Corporate Units,” will be remarketed.
In consultation with the remarketing agent and without the consent of any holders of Notes, we may elect (but shall not be required to elect) to remarket the Notes as fixed-rate Notes or floating-rate Notes and, in the case of floating-rate Notes, provide that the interest on the Notes will be equal to an index rate determined by the Company plus a spread determined by the remarketing agent, in consultation with the Company, in which case interest on the Notes may be calculated on the basis of a 365 day year and the actual number of days elapsed (or such other basis as is customarily used for floating-rate Notes bearing interest at a rate based on such index rate).
All such modifications shall take effect only if the remarketing is successful, without the consent of the holders, upon the earlier of the optional remarketing settlement date and the purchase contract settlement date, and will apply to all of the Notes whether or not included in the remarketing. See “Description of the Junior Subordinated Debentures—Remarketing.” If we conduct an optional remarketing that is not successful, we may change the elections described above prior to the final remarketing period.
In order to remarket the Notes, the remarketing agent, in consultation with us, may reset the interest rate on the Notes (either upward or downward), or if the Notes are remarketed as floating-rate Notes, determine the interest rate spread applicable to the Notes, in order to produce the required price in the remarketing, as discussed under “—Optional Remarketing” and “—Final Remarketing” below. The interest deferral provisions of the Notes will not apply after a successful remarketing.
We will use commercially reasonable efforts to ensure that, if required by applicable law, a registration statement, including a prospectus, with regard to the full amount of the Notes to be remarketed will be effective under the securities laws in a form that may be used by the
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remarketing agent in connection with the remarketing (unless a registration statement is not required under the applicable laws and regulations that are in effect at that time or unless we conduct any remarketing in accordance with an exemption under the securities laws).
We will separately pay a fee to the remarketing agent for its services as remarketing agent. Holders whose Notes are remarketed will not be responsible for the payment of any remarketing fee in connection with the remarketing.
Optional Remarketing
Unless a termination event has occurred, we may elect, at our option, to engage the remarketing agent pursuant to the terms of the remarketing agreement, to remarket the Notes over a period selected by us that begins on or after May 11, 2023 (the third business day immediately preceding the last interest payment date prior to the purchase contract settlement date) and ends any time on or before July 27, 2023 (the eighth calendar day immediately preceding the first day of the final remarketing period). We refer to this period as the “optional remarketing period,” a remarketing that occurs during the optional remarketing period as an “optional remarketing” and the date the Notes are priced in an optional remarketing as the “optional remarketing date.” In any optional remarketing, the aggregate principal amount of the Notes that are a part of Corporate Units and any separate Notes whose holders have elected to participate in the optional remarketing, as described under “Description of the Junior Subordinated Debentures—Remarketing of the Notes That Are Not Included in Corporate Units,” will be remarketed. If we elect to conduct an optional remarketing, the remarketing agent will use its commercially reasonable efforts to obtain a price for the Notes that results in proceeds of at least 100% of the aggregate of the Treasury portfolio purchase price (as defined below) and the separate Notes purchase price (as defined below). To obtain that price, the remarketing agent may, in consultation with us, reset the interest rate on the Notes remarketed as fixed-rate Notes, or determine the interest rate spread for the Notes remarketed as floating-rate Notes, as described under “Description of the Junior Subordinated Debentures—Interest Rate Reset.” We will request that the depository notify its participants holding Corporate Units, Treasury Units and separate Notes of our election to conduct an optional remarketing no later than five business days prior to the date we begin the optional remarketing.
Notwithstanding anything in this prospectus supplement to the contrary, we may not elect to conduct an optional remarketing if we are then deferring interest on the Notes. See “Description of the Junior Subordinated Debentures—Option to Defer Interest Payments.”
An optional remarketing on any remarketing date will be considered successful if the remarketing agent is able to remarket the Notes for a price of at least 100% of the Treasury portfolio purchase price and the separate Notes purchase price.
Following a successful optional remarketing of the Notes, on the optional remarketing settlement date (as defined below), the portion of the remarketing proceeds equal to the Treasury portfolio purchase price will, except as described below, be used to purchase the Treasury portfolio and the remaining proceeds attributable to the Notes underlying the Corporate Units will be remitted to the purchase contract agent for distribution pro rata to the holders of such Corporate Units. The portion of the proceeds attributable to the separate Notes sold in the remarketing will be remitted to the custodial agent for distribution on the optional remarketing settlement date pro rata to the holders of such separate Notes.
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If we elect to conduct an optional remarketing and the remarketing is successful:
•settlement with respect to the remarketed Notes will occur on the second business day following the optional remarketing date, unless the remarketed Notes are priced after 4:30 p.m. New York time on the optional remarketing date, in which case settlement will occur on the third business day following the optional remarketing date (we refer to such settlement date as the “optional remarketing settlement date”);
•the interest rate on the Notes will be reset, or, if we remarketed the Notes as floating-rate Notes, the interest rate spread will be determined, by the remarketing agent in consultation with us on the optional remarketing date and will become effective on the optional remarketing settlement date, if applicable;
•except in the case when the Notes are remarketed as floating-rate Notes, interest on the Notes will be payable semi-annually;
• the interest deferral provisions will cease to apply to the Notes;
•the other modifications to the terms of the Notes, as described under “—Remarketing,” will become effective;
•after the optional remarketing settlement date, your Corporate Units will consist of a purchase contract and the applicable ownership interest in the Treasury portfolio (or cash), as described herein; and
•you may no longer create Treasury Units or recreate Corporate Units from Treasury Units.
If we do not elect to conduct an optional remarketing during the optional remarketing period or no optional remarketing succeeds for any reason, the Notes will continue to be a component of the Corporate Units or will continue to be held separately and the remarketing agent will use its commercially reasonable efforts to remarket the Notes during the final remarketing period.
For the purposes of a successful optional remarketing, “Treasury portfolio purchase price” means the lowest aggregate ask-side price quoted by a primary U.S. government securities dealer in New York City to the quotation agent selected by us between 9:00 a.m. and 4:00 p.m., New York City time, on the optional remarketing date for the purchase of the Treasury portfolio for settlement on the optional remarketing settlement date; provided that if the Treasury portfolio consists of cash, “Treasury portfolio purchase price” means the amount of such cash.
Following a successful optional remarketing, the collateral agent will purchase, at the Treasury portfolio purchase price, a Treasury portfolio consisting of:
•U.S. Treasury securities (or principal or interest strips thereof) that mature on or prior to the purchase contract settlement date in an aggregate amount at maturity equal to the principal amount of the Notes underlying the undivided beneficial ownership interests in Notes included in the Corporate Units on the optional remarketing date; and

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•U.S. Treasury securities (or principal or interest strips thereof) that mature on or prior to the purchase contract settlement date in an aggregate amount equal to the aggregate interest payment (assuming no reset of the interest rate) that would have been paid to the holders of the Corporate Units on the purchase contract settlement date on the principal amount of the Notes underlying the undivided beneficial ownership interests in Notes included in the Corporate Units on the optional remarketing date.
If U.S. Treasury securities (or principal or interest strips thereof) that are to be included in the Treasury portfolio in connection with a successful optional remarketing have a yield that is less than zero, the Treasury portfolio will consist of an amount in cash equal to the aggregate principal amount at maturity of the U.S. Treasury securities described in the bullet points above. If the provisions set forth in this paragraph apply, references in this prospectus supplement to a “Treasury security” and “U.S. Treasury securities (or principal or interest strips thereof)” in connection with the Treasury portfolio will, thereafter, be deemed to be references to such amount in cash.
The applicable ownership interests in the Treasury portfolio will be substituted for the undivided beneficial ownership interests in Notes that are components of the Corporate Units and the portion of the Treasury portfolio described in the first bullet will be pledged to us through the collateral agent to secure the Corporate Unit holders’ obligation under the purchase contracts. On the purchase contract settlement date, for each Corporate Unit, $50.00 of the proceeds from the Treasury portfolio will automatically be applied to satisfy the Corporate Unit holder’s obligation to purchase common stock under the purchase contract. In addition, proceeds from the portion of the Treasury portfolio described in the second bullet, which will equal the interest payment (without reference to the reset of the interest rate) that would have been paid on the Notes that were components of the Corporate Units at the time of remarketing, will be paid on the purchase contract settlement date to the holders of the Corporate Units.
If we elect to remarket the Notes during the optional remarketing period and a successful remarketing has not occurred on or prior to July 27, 2023 (the last day of the optional remarketing period), we will cause a notice of the failed remarketing to be published no later than 9:00 a.m., New York City time, on the business day immediately following the last date of the optional remarketing period. This notice will be validly published by making a timely release to any appropriate news agency, including Bloomberg Business News and the Dow Jones News Service. We will similarly cause a notice of a successful remarketing of the Notes to be published no later than 9:00 a.m., New York City time, on the business day immediately following the date of such successful remarketing.
On each business day during any optional remarketing period, we have the right in our sole and absolute discretion to determine whether or not an optional remarketing will be attempted. At any time and from time to time during the optional remarketing period prior to the announcement of a successful optional remarketing, we have the right to postpone any optional remarketing in our sole and absolute discretion.
Final Remarketing
Unless a termination event or a successful optional remarketing has previously occurred, we will remarket the Notes during the five business day period ending on, and including, August
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10, 2023 (the third business day immediately preceding the purchase contract settlement date). We refer to this period as the “final remarketing period,” the remarketing during this period as the “final remarketing” and the date the Notes are priced in the final marketing as the “final remarketing date.” In the final remarketing, the aggregate principal amount of the Notes that are a part of Corporate Units (except where the holder has elected to settle the purchase contract through payment of separate cash) and any separate Notes whose holders have elected to participate in the final remarketing will be remarketed. The remarketing agent will use its commercially reasonable efforts to obtain a price for the Notes to be remarketed that results in proceeds of at least 100% of the principal amount of all the Notes offered in the remarketing. To obtain that price, the remarketing agent, in consultation with us, may reset the interest rate on the Notes if the Notes are remarketed as fixed-rate Notes, or determine the interest rate spread on the Notes if the Notes are remarketed as floating-rate Notes, as described under “Description of the Junior Subordinated Debentures—Interest Rate Reset.” We will request that the depository notify its participants holding Corporate Units, Treasury Units and separate Notes of the final remarketing no later than seven days prior to the first day of the final remarketing period. In such notice, we will set forth the dates of the final remarketing period, applicable procedures for holders of separate Notes to participate in the final remarketing, the applicable procedures for holders of Corporate Units to create Treasury Units and for holders of Treasury Units to recreate Corporate Units, the applicable procedures for holders of Corporate Units to settle their purchase contracts early and any other applicable procedures, including the procedures that must be followed by a holder of separate Notes in the case of a failed remarketing if a holder of separate Notes wishes to exercise its right to put its Notes to us as described below and under “Description of the Junior Subordinated Debentures—Put Option upon Failed Remarketing.” We have the right to postpone the final remarketing in our sole and absolute discretion on any day prior to the last three business days of the final remarketing period.
A remarketing during the final remarketing period will be considered successful if the remarketing agent is able to remarket the Notes for a price of at least 100% of the aggregate principal amount of all the Notes offered in the remarketing.
If the final remarketing is successful:
•settlement with respect to the remarketed Notes will occur on the purchase contract settlement date;
•the interest rate of the Notes will be reset, or, if the Notes are remarketed as floating-rate Notes, the interest rate spread will be determined, by the remarketing agent in consultation with us, and will become effective on the reset effective date, which will be the purchase contract settlement date, as described under “Description of the Junior Subordinated Debentures—Interest Rate Reset” below;
• the other modifications to the terms of the Notes, as described under “—Remarketing,” will become effective; and
•the collateral agent will remit the portion of the proceeds equal to the total principal amount of the Notes underlying the Corporate Units to us to satisfy in full the Corporate Unit holders’ obligations to purchase common stock under the related purchase contracts, any excess proceeds attributable to Notes underlying Corporate Units that
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were remarketed will be remitted to the purchase contract agent for distribution pro rata to the holders of such Notes and proceeds from the final remarketing attributable to the separate Notes remarketed will be remitted to the custodial agent for distribution pro rata to the holders of the remarketed separate Notes.
Unless a termination event has occurred, a holder has effected an early settlement or a fundamental change early settlement, or there has been a successful optional remarketing, each Corporate Unit holder has the option at any time on or after the date we give notice of a final remarketing to notify the purchase contract agent at any time prior to 4:00 p.m., New York City time, on the second business day immediately prior to the first day of the final remarketing period of its intention to settle the related purchase contracts on the purchase contract settlement date with separate cash and to provide that cash on or prior to the business day immediately prior to the first day of the final remarketing period, as described under “—Notice to Settle with Cash.” The Notes of any holder of Corporate Units who has not given this notice or failed to deliver the cash will be remarketed during the final remarketing period. In addition, holders of Notes that do not underlie Corporate Units may elect to participate in the remarketing as described under “Description of the Junior Subordinated Debentures—Remarketing of Notes That Are Not Included in Corporate Units.”
If, in spite of using its commercially reasonable efforts, the remarketing agent cannot remarket the Notes during the final remarketing period at a price equal to or greater than 100% of the aggregate principal amount of the Notes offered in the remarketing, a condition precedent set forth in the remarketing agreement has not been fulfilled or a successful remarketing has not occurred for any other reason, in each case resulting in a “failed remarketing,” holders of all Notes will have the right to put their Notes to us for an amount equal to the principal amount of their Notes (the “put price”). The conditions precedent in the remarketing agreement will include, but not be limited to, the timely filing with the SEC of all material related to the remarketing required to be filed by us, the truth and correctness of certain representations and warranties made by us in the remarketing agreement, the furnishing of certain officer’s certificates to the remarketing agent, and the receipt by the remarketing agent of customary “comfort letters” from our auditors and opinions of counsel. A holder of Corporate Units will be deemed to have automatically exercised this put right with respect to the Notes underlying such Corporate Units unless the holder has provided a written notice to the purchase contract agent of its intention to settle the purchase contract with separate cash as described below under “—Notice to Settle with Cash” prior to 4:00 p.m., New York City time, on the second business day immediately prior to the purchase contract settlement date, and on or prior to the business day immediately preceding the purchase contract settlement date has delivered the $50.00 in cash per purchase contract. Settlement with separate cash may only be effected in integral multiples of 20 Corporate Units. If a holder of Corporate Units elects to settle with separate cash, upon receipt of the required cash payment, the related Notes underlying the Corporate Units will be released from the pledge under the purchase contract and pledge agreement and delivered promptly to the purchase contract agent for delivery to the holder. The holder of the Corporate Units will then receive the applicable number of shares of our common stock on the purchase contract settlement date. The cash received by the collateral agent upon this settlement with separate cash may be invested in permitted investments, as defined in the purchase contract and pledge agreement, and the portion of the proceeds equal to the aggregate purchase price of all purchase contracts of such holders will be paid to us on the purchase contract settlement date. Any excess funds received by the collateral agent in respect of any such permitted
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investments over the aggregate purchase price remitted to us in satisfaction of the obligations of the holders under the purchase contracts will be distributed to the purchase contract agent for ratable payment to the applicable holders who settled with separate cash. Unless a holder of Corporate Units has elected to settle the related purchase contracts with separate cash and delivered the separate cash on or prior to the business day immediately preceding the purchase contract settlement date, the holder will be deemed to have elected to apply the put price against the holder’s obligations to pay the aggregate purchase price for the shares of our common stock to be issued under the related purchase contracts, thereby satisfying the obligations in full, and we will deliver to the holder our common stock pursuant to the related purchase contracts.
If a successful final remarketing has not occurred on or prior to August 10, 2023 (the last day of the final remarketing period), we will cause a notice of the failed remarketing of the Notes to be published no later than 9:00 a.m., New York City time, on the business day immediately following the last date of the final remarketing period. This notice will be validly published by making a timely release to any appropriate news agency, including Bloomberg Business News and the Dow Jones News Service.
Early Settlement
Subject to the conditions described below, a holder of Corporate Units or Treasury Units may settle the related purchase contracts at any time prior to 4:00 p.m., New York City time, on the second business day immediately preceding the purchase contract settlement date, other than during a blackout period in the case of Corporate Units. An early settlement may be made only in integral multiples of 20 Corporate Units or 20 Treasury Units; however, if the Treasury portfolio has replaced the Notes as a component of the Corporate Units following a successful optional remarketing, holders of Corporate Units may settle early only in integral multiples of 160,000 Corporate Units. In order to settle purchase contracts early, a holder of Equity Units must deliver to the purchase contract agent at the corporate trust office of the purchase contract agent or its agent, in each case, in the Borough of Manhattan, The City of New York (1) a completed “Election to Settle Early” form, along with the Corporate Unit or Treasury Unit certificate, if they are in certificated form and (2) a cash payment in immediately available funds in an amount equal to:
•$50.00 times the number of purchase contracts being settled; plus
•if the early settlement date occurs during the period from the close of business on any record date next preceding any contract adjustment payment date to the opening of business on such contract adjustment payment date, an amount equal to the contract adjustment payments payable on such contract adjustment payment date, unless we have elected to defer the contract adjustment payments payable on such contract adjustment payment date.
So long as you hold Equity Units as a beneficial interest in a global security certificate deposited with the depository, procedures for early settlement will also be governed by standing arrangements between the depository and the purchase contract agent.
The early settlement right is also subject to the condition that, if required under U.S. federal securities laws, we have a registration statement under the Securities Act in effect with respect to the shares of common stock and other securities, if any, deliverable upon settlement of a purchase
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contract. We have agreed that, if such a registration statement is required, we will use our commercially reasonable efforts to (1) have a registration statement in effect covering those shares of common stock and other securities, if any, to be delivered in respect of the purchase contracts being settled and (2) provide a prospectus in connection therewith, in each case in a form that may be used in connection with the early settlement right (it being understood that if there is a material business transaction or development that has not yet been publicly disclosed, we will not be required to file such registration statement or provide such a prospectus, and the early settlement right will not be available, until we have publicly disclosed such transaction or development; provided that we will use commercially reasonable efforts to make such disclosure as soon as it is commercially reasonable to do so). In the event that a holder seeks to exercise its early settlement right and a registration statement is required to be effective in connection with the exercise of such right but no such registration statement is then effective, the holder’s exercise of such right will be void unless and until such a registration statement is effective.
Upon early settlement, except as described below in “—Early Settlement Upon a Fundamental Change,” we will sell, and the holder will be entitled to buy, the minimum settlement rate of 0.5003 shares of our common stock (or in the case of an early settlement following a reorganization event, such number of exchange property units, as described under “—Reorganization Events” below) for each purchase contract being settled (regardless of the market price of our common stock on the date of early settlement), subject to adjustment under the circumstances described under “—Anti-dilution Adjustments” below. We will cause, no later than the second business day after the applicable early settlement date, (1) the shares of our common stock to be issued and (2) the related Notes or applicable ownership interests in the Treasury portfolio or Treasury securities, as the case may be, underlying the Equity Units and securing such purchase contracts to be released from the pledge under the purchase contract and pledge agreement, and delivered to the purchase contract agent for delivery to the holder. Upon early settlement, the holder will be entitled to receive any accrued and unpaid contract adjustment payments (including any accrued and unpaid deferred contract adjustment payments and compounded contract adjustment payments thereon) to, but excluding, the contract adjustment payment date immediately preceding the early settlement date. The holder’s right to receive future contract adjustment payments will also terminate.
If the purchase contract agent receives a completed “Election to Settle Early” form (along with the Corporate Unit or Treasury Unit certificate, if they are in certificated form) and payment of $50.00 for each purchase contract being settled (and, if required, an amount equal to the contract adjustment payments payable on the next contract adjustment payment date) prior to 4:00 p.m., New York City time, on any business day and all conditions to early settlement have been satisfied, then that day will be considered the early settlement date. If the purchase contract agent receives the foregoing at or after 4:00 p.m., New York City time, on any business day or at any time on a day that is not a business day, then the next business day will be considered the early settlement date.
Early Settlement Upon a Fundamental Change
If a “fundamental change” (as defined below) occurs prior to the 30th scheduled trading day preceding the purchase contract settlement date, then, following the fundamental change, each holder of a purchase contract, subject to certain conditions described in this prospectus supplement, will have the right to accelerate and settle the purchase contract early on the fundamental change
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early settlement date (defined below) at the settlement rate determined as if the applicable market value were determined, for such purpose, based on the market value averaging period starting on the 23rd scheduled trading day prior to the fundamental change early settlement date and ending on the third scheduled trading day immediately preceding the fundamental change early settlement date, plus an additional make-whole amount of shares (such additional make-whole amount of shares being hereafter referred to as the “make-whole shares”). We refer to this right as the “fundamental change early settlement right.”
If 20 trading days for our common stock have not occurred during the deemed market value averaging period referred to in the preceding paragraph, all remaining trading days will be deemed to occur on the third scheduled trading day immediately prior to the fundamental change early settlement date and the VWAP of our common stock for each of the remaining trading days will be the VWAP of our common stock on that third scheduled trading day or, if such day is not a trading day, the closing price as of such day.
We will provide each of the holders with a notice of the completion of a fundamental change within four scheduled trading days after the effective date of a fundamental change. The notice will specify (1) a date (subject to postponement as described below, the “fundamental change early settlement date”), which will be at least 26 scheduled trading days after the date of such notice and one business day before the purchase contract settlement date, on which date we will deliver shares of our common stock to holders who exercise the fundamental change early settlement right, (2) the date by which holders must exercise the fundamental change early settlement right, which will be no earlier than the second scheduled trading day before the fundamental change early settlement date, (3) the first scheduled trading day of the deemed market value averaging period, which will be the 23rd scheduled trading day prior to the fundamental change early settlement date, the reference price, the threshold appreciation price and the fixed settlement rates, (4) the amount and kind (per share of common stock) of the cash, securities and other consideration receivable by the holder upon settlement and (5) the amount of accrued and unpaid contract adjustment payments (including any deferred contract adjustment payments and compounded contract adjustment payments thereon), if any, that will be paid upon settlement to holders exercising the fundamental change early settlement right. To exercise the fundamental change early settlement right, you must deliver to the purchase contract agent at the corporate trust office of the purchase contract agent or its agent, in each case, in the Borough of Manhattan, The City of New York, during the period beginning on the date we deliver notice that a fundamental change has occurred and ending at 4:00 p.m., New York City time, on the third scheduled trading day immediately preceding the fundamental change early settlement date (such period, subject to extension as described below, the “fundamental change exercise period”), the certificate evidencing your Corporate Units or Treasury Units if they are held in certificated form, and payment of $50.00 for each purchase contract being settled in immediately available funds.
A “fundamental change” will be deemed to have occurred if any of the following occurs:
(1)a “person” or “group” within the meaning of Section 13(d) of the Exchange Act, as in effect on the issue date of the Corporate Units, has become the direct or indirect “beneficial owner,” as defined in Rule 13d-3 under the Exchange Act, of shares of our common stock representing more than 50% of the voting power of our common stock;
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(2)(A) we are involved in a consolidation with or merger into any other person, or any merger of another person into us, or any other similar transaction or series of related transactions (other than a merger, consolidation or similar transaction that does not result in the conversion or exchange of outstanding shares of our common stock), in each case, in which 90% or more of the outstanding shares of our common stock are exchanged for or converted into cash, securities or other property, greater than 10% of the value of which consists of cash, securities or other property that is not (or will not be upon or immediately following the effectiveness of such consolidation, merger or other transaction) common stock listed on the New York Stock Exchange, the NASDAQ Global Select Market or the NASDAQ Global Market (or any of their respective successors) or (B) the consummation of any sale, lease or other transfer in one transaction or a series of related transactions of all or substantially all of our consolidated assets to any person other than one of our wholly-owned subsidiaries;
(3)our common stock ceases to be listed on at least one of the New York Stock Exchange, the NASDAQ Global Select Market or the NASDAQ Global Market (or any of their respective successors) or the announcement by any of such exchanges on which our common stock is then listed or admitted for trading that our common stock will no longer be so listed or admitted for trading, unless our common stock has been accepted for listing or admitted for trading on another of such exchanges; or
(4)our shareholders approve our liquidation, dissolution or termination;
provided that a transaction or event or series of related transactions that constitute a fundamental change pursuant to both clauses (1) and (2) above will be deemed to constitute a fundamental change solely pursuant to clause (2) of this definition of “fundamental change.”
If you exercise the fundamental change early settlement right, we will deliver to you on the fundamental change early settlement date for each purchase contract with respect to which you have elected fundamental change early settlement, a number of shares (or exchange property units, if applicable) equal to the settlement rate described above plus the additional make-whole shares. In addition, on the fundamental change early settlement date, we will pay you the amount of any accrued and unpaid contract adjustment payments (including any deferred contract adjustment payments and compounded contract adjustment payments thereon) to, but excluding, the fundamental change early settlement date, unless the date on which the fundamental change early settlement right is exercised occurs following any record date and prior to the related scheduled contract adjustment payment date, and we are not deferring the related contract adjustment payment, in which case we will instead pay all accrued and unpaid contract adjustment payments to the holder as of such record date. You will also receive on the fundamental change early settlement date the Notes or the applicable ownership interest in the Treasury portfolio or Treasury securities underlying the Corporate Units or Treasury Units, as the case may be, with respect to which you are effecting a fundamental change early settlement, which, in each case, shall have been released from the pledge under the purchase contract and pledge agreement. If you do not elect to exercise your fundamental change early settlement right, your Corporate Units or Treasury Units will remain outstanding and will be subject to normal settlement on the purchase contract settlement date.

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We have agreed that, if required under the U.S. federal securities laws, we will use our commercially reasonable efforts to (1) have in effect throughout the fundamental change exercise period a registration statement covering the common stock and other securities, if any, to be delivered in respect of the purchase contracts being settled and (2) provide a prospectus in connection therewith, in each case in a form that may be used in connection with the fundamental change early settlement (it being understood that for so long as there is a material business transaction or development that has not yet been publicly disclosed (but in no event for a period longer than 90 days), we will not be required to file such registration statement or provide such a prospectus, and the fundamental change early settlement right will not be available, until we have publicly disclosed such transaction or development; provided that we will use commercially reasonable efforts to make such disclosure as soon as it is commercially reasonable to do so). In the event that a holder seeks to exercise its fundamental change early settlement right and a registration statement is required to be effective in connection with the exercise of such right but no such registration statement is then effective or a blackout period is continuing, the holder’s exercise of such right will be void unless and until such a registration statement is effective and no blackout period is continuing. The fundamental change exercise period will be extended by the number of days during such period on which no such registration statement is effective or a blackout period is continuing (provided that the fundamental change exercise period will not be extended beyond the third scheduled trading day preceding the purchase contract settlement date) and the fundamental change early settlement date will be postponed to the third scheduled trading day following the end of the fundamental change exercise period. We will provide each of the holders with a notice of any such extension and postponement at least 23 scheduled trading days prior to any such extension and postponement.
Unless the Treasury portfolio has replaced the Notes as a component of the Corporate Units as result of a successful remarketing, holders of Corporate Units may exercise the fundamental change early settlement right only in integral multiples of 20 Corporate Units. If the Treasury portfolio has replaced the Notes as a component of Corporate Units, holders of the Corporate Units may exercise the fundamental change early settlement right only in integral multiples of 160,000 Corporate Units.
A holder of Treasury Units may exercise the fundamental change early settlement right only in integral multiples of 20 Treasury Units.
Calculation of Make-Whole Shares. The number of make-whole shares per purchase contract applicable to a fundamental change early settlement will be determined by reference to the table below, based on the date on which the fundamental change occurs or becomes effective (the “effective date”) and the “stock price” in the fundamental change, which will be:
•in the case of a fundamental change described in clause (2) above where the holders of our common stock receive only cash in the fundamental change, the cash amount paid per share of our common stock; or
•otherwise, the average of the closing prices of our common stock over the 20 trading-day period ending on the trading day immediately preceding the effective date of the fundamental change.
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Stock Price on Effective Date	
Effective
Date	$30.00	$40.00	$50.00	$75.00	$83.29	$90.00	$99.95	$125.00	$150.00	$175.00	$200.00	$250.00	$300.00	
08/14/2020	0.1265	0.0922	0.0693	0.0186	0.0000	0.0346	0.0737	0.0454	0.0304	0.0224	0.0177	0.0122	0.0088	
08/15/2021	0.1102	0.0810	0.0621	0.0161	0.0000	0.0300	0.0676	0.0383	0.0250	0.0189	0.0154	0.0112	0.0085	
08/15/2022	0.0682	0.0504	0.0395	0.0072	0.0000	0.0175	0.0516	0.0224	0.0142	0.0113	0.0095	0.0071	0.0055	
08/15/2023	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	

The stock prices set forth in the second row of the table (i.e., the column headers) will be adjusted upon the occurrence of certain events requiring anti-dilution adjustments to the fixed settlement rates in a manner inversely proportional to the adjustments to the fixed settlement rates.
Each of the make-whole share amounts in the table will be subject to adjustment in the same manner and at the same time as the fixed settlement rates as set forth under “—Anti-dilution Adjustments.”
The exact stock price and effective date applicable to a fundamental change may not be set forth on the table, in which case:
•if the stock price is between two stock prices on the table or the effective date is between two effective dates on the table, the amount of make-whole shares will be determined by straight line interpolation between the make-whole share amounts set forth for the higher and lower stock prices and the two effective dates based on a 365-day year, as applicable;
•if the stock price is in excess of $300.00 per share (subject to adjustment in the same manner as the stock prices set forth in the second row of the table as described above), then the make-whole share amount will be zero; and
•if the stock price is less than $30.00 per share (subject to adjustment in the same manner as the stock prices set forth in the second row of the table as described above) (the “minimum stock price”), then the make-whole share amount will be determined as if the stock price equaled the minimum stock price, using straight line interpolation, as described above, if the effective date is between two effective dates on the table.
Notice to Settle with Cash
Unless a termination event has occurred, a holder effects an early settlement or a fundamental change early settlement with respect to the underlying purchase contract, or a successful remarketing has occurred, a holder of Corporate Units may settle the related purchase contract with separate cash by delivering the Corporate Unit certificate, if in certificated form, to the purchase contract agent at the corporate trust office of the purchase contract agent or its agent, in each case, in the Borough of Manhattan, The City of New York with the completed “Notice to Settle with Cash” form at any time on or after the date we give notice of a final remarketing and prior to 4:00 p.m., New York City time on the second business day immediately preceding the first day of the final remarketing period or, if there has been a failed final remarketing, on the second business day immediately preceding the purchase contract settlement date. Holders of Corporate Units may only cash-settle Corporate Units in integral multiples of 20 Corporate Units.
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The holder must also deliver to the securities intermediary the required cash payment in immediately available funds. Such payment must be delivered prior to 4:00 p.m., New York City time, on the first business day immediately preceding the final remarketing period or, if there has been a failed remarketing, on the first business day immediately preceding the purchase contract settlement date.
Upon receipt of the cash payment, the related Note will be released from the pledge arrangement and transferred to the purchase contract agent for distribution to the holder of the related Corporate Units. The holder of the Corporate Units will then receive the applicable number of shares of our common stock on the purchase contract settlement date.
If a holder of Corporate Units that has given notice of its election to settle with cash fails to deliver the cash by the applicable time and date specified above, such holder shall be deemed to have consented to the disposition of its Notes in the final remarketing, or to have exercised its put right (as described under “—Remarketing” above), in each case, as applicable.
Any cash received by the collateral agent upon cash settlement may be invested in permitted investments, as defined in the purchase contract and pledge agreement, and the portion of the proceeds equal to the aggregate purchase price of all purchase contracts of such holders will be paid to us on the purchase contract settlement date. Any excess funds received by the collateral agent in respect of permitted investments over the aggregate purchase price remitted to us in satisfaction of the obligations of the holders under the purchase contracts will be distributed to the purchase contract agent for payment to the holders who settled with cash.
Contract Adjustment Payments
Contract adjustment payments in respect of Corporate Units and Treasury Units will be fixed at a rate per year of 4.825% of the stated amount of $50.00 per purchase contract. Contract adjustment payments payable for any period will be computed on the basis of a 360-day year of twelve 30-day months. Contract adjustment payments will accrue from the date of issuance of the purchase contracts and will be payable quarterly in arrears on February 15, May 15, August 15 and November 15 of each year, commencing November 15, 2020.
Contract adjustment payments will be payable to the holders of purchase contracts as they appear on the books and records of the purchase contract agent at the close of business on the relevant record dates, which will be the 30th day of the month immediately preceding the month in which the relevant payment date falls (or, if such day is not a business day, the next preceding business day) or if the Equity Units are held in book-entry form, the “record date” will be the business day immediately preceding the applicable payment date. These distributions will be paid through the purchase contract agent, which will hold amounts received in respect of the contract adjustment payments for the benefit of the holders of the purchase contracts relating to the Equity Units. Subject to any applicable laws and regulations, each such payment will be made as described under “Certain Provisions of the Purchase Contract and Pledge Agreement—Book-Entry System.”
If any date on which contract adjustment payments are to be made on the purchase contracts related to the Corporate Units or Treasury Units is not a business day, then payment of the contract
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adjustment payments payable on that date will be made on the next succeeding day that is a business day, and no interest or payment will be paid in respect of the delay.
For the avoidance of doubt, subject to our right to defer contract adjustment payments, all record holders of purchase contracts on any record date will be entitled to receive the full contract adjustment payment due on the related contract adjustment payment date regardless of whether the holder of such purchase contract elects to settle such purchase contract early (whether at its option or in connection with a fundamental change) following such record date.
Our obligations with respect to contract adjustment payments will be subordinated and junior in right of payment to our obligations under any of our Senior Indebtedness (as defined under “Description of the Junior Subordinated Debentures—Subordination”) and will rank on parity with the Notes.
We may, at our option and upon prior written notice to the purchase contract agent, defer all or part of the contract adjustment payments, but not beyond the purchase contract settlement date (or, with respect to an early settlement upon a fundamental change, not beyond the fundamental change early settlement date or, with respect to an early settlement other than upon a fundamental change, not beyond the contract adjustment payment date immediately preceding the early settlement date).
Deferred contract adjustment payments will accrue additional contract adjustment payments at the rate equal to 6.125% per annum (which is equal to the rate of total distributions on the Corporate Units), compounded on each contract adjustment payment date, to, but excluding, the contract adjustment payment date on which such deferred contract adjustment payments are paid. We refer to additional contract adjustment payments that accrue on deferred contract adjustment payments as “compounded contract adjustment payments.” We may pay any such deferred contract adjustment payments (including compounded contract adjustment payments thereon) on any scheduled contract adjustment payment date; provided that in order to pay deferred contract adjustment payments on any scheduled contract adjustment payment date other than the purchase contract settlement date, we must deliver written notice thereof to holders of the Equity Units and the purchase contract agent on or before the relevant record date. If the purchase contracts are terminated (upon the occurrence of certain events of bankruptcy, insolvency or similar reorganization with respect to us), the right to receive contract adjustment payments and deferred contract adjustment payments (including compounded contract adjustment payments thereon) will also terminate.
If we exercise our option to defer the payment of contract adjustment payments, then, until the deferred contract adjustment payments (including compounded contract adjustment payments thereon) have been paid, we will not (1) declare or pay any dividends on, or make any distributions on, or redeem, purchase or acquire, or make a liquidation payment with respect to, any shares of our capital stock, (2) make any payment of principal of, or interest or premium, if any, on, or repay, repurchase or redeem any of our debt securities that rank on parity with, or junior to, the contract adjustment payments, or (3) make any guarantee payments under any guarantee by us of securities of any of our subsidiaries if our guarantee ranks on parity with, or junior to, the contract adjustment payments.
The restrictions listed above do not apply to:
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(a)purchases, redemptions or other acquisitions of our capital stock in connection with any employment contract, benefit plan or other similar arrangement with or for the benefit of employees, officers, directors, agents or consultants or a stock purchase or dividend reinvestment plan, or the satisfaction of our obligations pursuant to any contract or security outstanding on the date that the contract adjustment payment is deferred requiring us to purchase, redeem or acquire our capital stock;
(b)any payment, repayment, redemption, purchase, acquisition or declaration of dividends described in clause (1) above as a result of a reclassification of our capital stock, or the exchange or conversion of all or a portion of one class or series of our capital stock, for another class or series of our capital stock;
(c)the purchase of fractional interests in shares of our capital stock pursuant to the conversion or exchange provisions of our capital stock or the security being converted or exchanged, or in connection with the settlement of stock purchase contracts outstanding on the date that the contract adjustment payment is deferred;
(d)dividends or distributions paid or made in our capital stock (or rights to acquire our capital stock), or repurchases, redemptions or acquisitions of capital stock in connection with the issuance or exchange of capital stock (or of securities convertible into or exchangeable for shares of our capital stock) and distributions in connection with the settlement of stock purchase contracts outstanding on the date that the contract adjustment payment is deferred;
(e)redemptions, exchanges or repurchases of, or with respect to, any rights outstanding under a shareholder rights plan outstanding on the date that the contract adjustment payment is deferred or the declaration or payment thereunder of a dividend or distribution of or with respect to rights in the future;
(f)payments on the Notes, any trust preferred securities, subordinated debentures, junior subordinated debentures or junior subordinated notes, or any guarantees of any of the foregoing, in each case, that rank equal in right of payment to the contract adjustment payments, so long as the amount of payments made on account of such securities or guarantees and the purchase contracts is paid on all such securities and guarantees and the purchase contracts then outstanding on a pro rata basis in proportion to the full payment to which each series of such securities, guarantees or purchase contracts is then entitled if paid in full; provided that, for the avoidance of doubt, we will not be permitted under the purchase contract and pledge agreement to make contract adjustment payments in part; or
(g)any payment of deferred interest or principal on, or repayment, redemption or repurchase of, parity or junior securities that, if not made, would cause us to breach the terms of the instrument governing such parity or junior securities.
Anti-dilution Adjustments
Each fixed settlement rate will be subject to the following adjustments:

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(1)Stock Dividends. If we pay or make a dividend or other distribution on our common stock in common stock, each fixed settlement rate in effect at the opening of business on the day following the date fixed for the determination of stockholders entitled to receive such dividend or other distribution will be increased by dividing:
•each fixed settlement rate by
•a fraction, the numerator of which will be the number of shares of our common stock outstanding at the close of business on the date fixed for such determination and the denominator of which will be the sum of such number of shares and the total number of shares constituting the dividend or other distribution.
If any dividend or distribution in this paragraph (1) is declared but not so paid or made, the new fixed settlement rates shall be readjusted, on the date that our board of directors determines not to pay or make such dividend or distribution, to the fixed settlement rates that would then be in effect if such dividend or distribution had not been declared.
(2)Stock Purchase Rights. If we issue to all or substantially all holders of our common stock rights, options, warrants or other securities (other than pursuant to a dividend reinvestment, share purchase or similar plan), entitling them to subscribe for or purchase shares of our common stock for a period expiring within 45 days from the date of issuance of such rights, options, warrants or other securities at a price per share of our common stock less than the current market price (as defined below) calculated as of the date fixed for the determination of stockholders entitled to receive such rights, options, warrants or other securities, each fixed settlement rate in effect at the opening of business on the day following the date fixed for such determination will be increased by dividing:
•each fixed settlement rate by
•a fraction, the numerator of which will be the number of shares of our common stock outstanding at the close of business on the date fixed for such determination plus the number of shares of our common stock which the aggregate consideration expected to be received by us upon the exercise of such rights, options, warrants or other securities would purchase at such current market price and the denominator of which will be the number of shares of our common stock outstanding at the close of business on the date fixed for such determination plus the number of shares of our common stock so offered for subscription or purchase.
If any right, option, warrant or other security described in this paragraph (2) is not exercised or converted prior to the expiration of the exercisability or convertibility thereof (and as a result no additional shares of common stock are delivered or issued pursuant to such right, option, or warrant or other security), the new fixed settlement rates shall be readjusted, as of the date of such expiration, to the fixed settlement rates that would then be in effect had the increase with respect to the issuance of such rights, options, warrants or other securities been made on the basis of delivery or issuance of only the number of shares of common stock actually delivered.

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For purposes of this clause (2), in determining whether any rights, options, warrants or other securities entitle the holders to subscribe for or purchase shares of the common stock at a price per share of our common stock less than the current market price on the date fixed for the determination of stockholders entitled to receive such rights, options, warrants or other securities, and in determining the aggregate price payable to exercise such rights, options, warrants or other securities, there shall be taken into account any consideration received by us for such rights, options, warrants or other securities and any amount payable on exercise or conversion thereof, the value of such consideration, if other than cash, to be determined in good faith by our board of directors.
(3)Stock Splits; Reverse Splits; and Combinations. If outstanding shares of our common stock shall be subdivided, split or reclassified into a greater number of shares of common stock, each fixed settlement rate in effect at the opening of business on the day following the day upon which such subdivision, split or reclassification becomes effective shall be proportionately increased, and, conversely, in case outstanding shares of our common stock shall each be combined or reclassified into a smaller number of shares of common stock, each fixed settlement rate in effect at the opening of business on the day following the day upon which such combination or reclassification becomes effective shall be proportionately reduced.
(4)Debt, Asset or Security Distributions. If we, by dividend or otherwise, distribute to all or substantially all holders of our common stock evidences of our indebtedness, assets or securities or any rights, options or warrants (or similar securities) to subscribe for, purchase or otherwise acquire evidences of our indebtedness, other assets or property of ours or other securities (but excluding any rights, options, warrants or other securities referred to in paragraph (2) above, any dividend or distribution paid exclusively in cash referred to in paragraph (5) below (in each case, whether or not an adjustment to the fixed settlement rates is required by such paragraph) and any dividend paid in shares of capital stock of any class or series, or similar equity interests, of or relating to a subsidiary or other business unit of ours in the case of a spin-off referred to below, or dividends or distributions referred to in paragraph (1) above), each fixed settlement rate in effect immediately prior to the close of business on the date fixed for the determination of stockholders entitled to receive such dividend or distribution shall be increased by dividing:
•each fixed settlement rate by
•a fraction, the numerator of which shall be the current market price of our common stock calculated as of the date fixed for such determination less the then fair market value (as determined in good faith by our board of directors) of the portion of the assets, securities or evidences of indebtedness so distributed applicable to one share of our common stock and the denominator of which shall be such current market price.
Notwithstanding the foregoing, if the then fair market value (as determined in good faith by our board of directors) of the portion of the assets, securities or evidences of indebtedness so distributed applicable to one share of our common stock exceeds the current market price of our common stock on the date fixed for the determination of stockholders entitled to receive such distribution, in lieu of the foregoing increase, each holder of a purchase contract shall receive, for
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each purchase contract, at the same time and upon the same terms as holders of shares of our common stock, the amount of such distributed assets, securities or evidences of indebtedness that such holder would have received if such holder owned a number of shares of our common stock equal to the maximum settlement rate on the record date for such dividend or distribution.
In the case of the payment of a dividend or other distribution on our common stock of shares of capital stock of any class or series, or similar equity interests, of or relating to a subsidiary or other business unit of ours, which are or will, upon issuance, be listed on a U.S. securities exchange or quotation system, which we refer to as a “spin-off,” each fixed settlement rate in effect immediately before the close of business on the date fixed for determination of stockholders entitled to receive that dividend or distribution will be increased by dividing:
•each fixed settlement rate by
•a fraction, the numerator of which is the current market price of our common stock and the denominator of which is such current market price plus the fair market value, determined as described below, of those shares of capital stock or similar equity interests so distributed applicable to one share of common stock.
The adjustment to the fixed settlement rate under the preceding paragraph will occur on:
•the 10th trading day from and including the effective date of the spin-off; or
•if the spin-off is effected simultaneously with an initial public offering of the securities being distributed in the spin-off and the ex-date for the spin-off occurs on or before the date that the initial public offering price of the securities being distributed in the spin-off is determined, the issue date of the securities being offered in such initial public offering.
For purposes of this section, “initial public offering” means the first time securities of the same class or type as the securities being distributed in the spin-off are offered to the public for cash.
Subject to the immediately following paragraph, the fair market value of the securities to be distributed to holders of our common stock means the average of the closing sale prices of those securities on the principal U.S. securities exchange or quotation system on which such securities are listed or quoted at that time over the first 10 trading days following the effective date of the spin-off. Also, for purposes of such a spin-off, the current market price of our common stock means the average of the closing sale prices of our common stock on the principal U.S. securities exchange or quotation system on which our common stock is listed or quoted at that time over the first 10 trading days following the effective date of the spin-off.
If, however, an initial public offering of the securities being distributed in the spin-off is to be effected simultaneously with the spin-off and the ex-date for the spin-off occurs on or before the date that the initial public offering price of the securities being distributed in the spin-off is determined, the fair market value of the securities being distributed in the spin-off means the initial public offering price, while the current market price of our common stock means the closing sale price of our common stock on the principal U.S. securities exchange or quotation system on which
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our common stock is listed or quoted at that time on the trading day on which the initial public offering price of the securities being distributed in the spin-off is determined.
If any dividend or distribution described in this paragraph (4) is declared but not so paid or made, the new fixed settlement rates shall be readjusted, as of the date our board of directors determines not to pay or make such dividend or distribution, to the fixed settlement rates that would then be in effect if such dividend or distribution had not been declared.
(5)Cash Distributions. If we, by dividend or otherwise, make distributions to all or substantially all holders of our common stock exclusively in cash during any quarterly period in an amount that exceeds $0.70 per share per quarter in the case of a regular quarterly dividend (such per share amount being referred to as the “reference dividend”), then immediately after the close of business on the date fixed for determination of the stockholders entitled to receive such distribution, each fixed settlement rate in effect immediately prior to the close of business on such date will be increased by dividing:
•each fixed settlement rate by
•a fraction, the numerator of which will be equal to the current market price on the date fixed for such determination less the amount, if any, by which the per share amount of the distribution exceeds the reference dividend and the denominator of which will be equal to such current market price.
Notwithstanding the foregoing, if (1) the amount by which the per share amount of the cash distribution exceeds the reference dividend exceeds (2) the current market price of our common stock on the date fixed for the determination of stockholders entitled to receive such distribution, in lieu of the foregoing increase, each holder of a purchase contract shall receive, for each purchase contract, at the same time and upon the same terms as holders of shares of our common stock, the amount of distributed cash that such holder would have received if such holder owned a number of shares of our common stock equal to the maximum settlement rate on the record date for such cash dividend or distribution.
The reference dividend will be subject to an inversely proportional adjustment whenever each fixed settlement rate is adjusted, other than pursuant to this paragraph (5). For the avoidance of doubt, the reference dividend will be zero in the case of a cash dividend that is not a regular quarterly dividend.
If any dividend or distribution described in this paragraph (5) is declared but not so paid or made, the new fixed settlement rate shall be readjusted, as of the date our board of directors determines not to pay or make such dividend or distribution, to the fixed settlement rate that would then be in effect if such dividend or distribution had not been declared.
(6)Tender and Exchange Offers. In the case that a tender offer or exchange offer made by us or any subsidiary for all or any portion of our common stock shall expire and such tender or exchange offer (as amended through the expiration thereof) requires the payment to stockholders (based on the acceptance (up to any maximum specified in the terms of the tender offer or exchange offer) of purchased shares) of an aggregate consideration having a fair market value per share of our common stock that exceeds the
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closing price of our common stock on the trading day next succeeding the last date on which tenders or exchanges may be made pursuant to such tender offer or exchange offer, then, immediately prior to the opening of business on the day after the date of the last time (which we refer to as the “expiration time”) tenders or exchanges could have been made pursuant to such tender offer or exchange offer (as amended through the expiration thereof), each fixed settlement rate in effect immediately prior to the close of business on the date of the expiration time will be increased by dividing:
•each fixed settlement rate by
•a fraction (1) the numerator of which will be equal to (a) the product of (i) the current market price on the date of the expiration time and (ii) the number of shares of common stock outstanding (including any tendered or exchanged shares) on the date of the expiration time less (b) the amount of cash plus the fair market value of the aggregate consideration payable to stockholders pursuant to the tender offer or exchange offer (assuming the acceptance by us of purchased shares (as defined below)), and (2) the denominator of which will be equal to the product of (a) the current market price on the date of the expiration time and (b) the result of (i) the number of shares of our common stock outstanding (including any tendered or exchanged shares) on the date of the expiration time less (ii) the number of all shares validly tendered, not withdrawn and accepted for payment on the date of the expiration time (such actually validly tendered or exchanged shares, up to any maximum acceptance amount specified by us in the terms of the tender offer or exchange offer, being referred to as the “purchased shares”).
For purposes of paragraphs (2) through (6) (except as otherwise expressly provided therein with respect to spin-offs) above, the “current market price” per share of our common stock or any other security on any day means the average VWAP of our common stock or such other security on the principal U.S. securities exchange or quotation system on which our common stock or such other security, as applicable, is listed or quoted at that time for the 10 consecutive trading days preceding the earlier of the trading day preceding the day in question and the trading day before the “ex-date” with respect to the issuance or distribution requiring such computation. For purposes of paragraph (6) above, the last day of the measurement period shall be the trading day next succeeding the last date on which tenders or exchanges may be made pursuant to the relevant tender offer or exchange offer. The term “ex-date,” when used with respect to any issuance or distribution on our common stock or any other security, means the first date on which our common stock or such other security, as applicable, trades, regular way, on the principal U.S. securities exchange or quotation system on which our common stock or such other security, as applicable, is listed or quoted at that time, without the right to receive the issuance or distribution.
We currently do not have a shareholders rights plan with respect to our common stock. To the extent that we have a shareholders rights plan involving the issuance of share purchase rights or other similar rights to all or substantially all holders of our common stock in effect upon settlement of a purchase contract, you will receive, in addition to the common stock issuable upon settlement of any purchase contract, the related rights for the common stock under the shareholders rights plan, unless, prior to any settlement of a purchase contract, the rights have separated from the common stock, in which case each fixed settlement rate will be adjusted at the time of
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separation as if we made a distribution to all holders of our common stock as described in clause (4) above, subject to readjustment in the event of the expiration, termination or redemption of the rights under the shareholder rights plan.
You may be treated as receiving a constructive distribution from us with respect to the purchase contract if (1) the fixed settlement rates are adjusted (or fail to be adjusted) and, as a result of the adjustment (or failure to adjust), your proportionate interest in our assets or earnings and profits is increased, and (2) the adjustment (or failure to adjust) is not made pursuant to a bona fide, reasonable anti-dilution formula. For example, if the fixed settlement rate is adjusted as a result of a distribution that is taxable to the holders of our common stock, such as a cash dividend, you will be deemed to have received a “constructive distribution” of our stock. Thus, under certain circumstances, an adjustment to the fixed settlement rates might give rise to a taxable dividend to you even though you will not receive any cash in connection with such adjustment. In addition, non-U.S. holders (as defined in “Certain United States Federal Income and Estate Tax Consequences”) may, in certain circumstances, be deemed to have received a distribution subject to U.S. federal withholding tax. See “Certain United States Federal Income and Estate Tax Consequences—U.S. Holders—Purchase Contracts” and “Certain United States Federal Income and Estate Tax Consequences—Non-U.S. Holders—Dividends.”
In addition, we may increase the fixed settlement rates if our board of directors deems it advisable to avoid or diminish any income tax to holders of our common stock resulting from any dividend or distribution of shares (or rights to acquire shares) or from any event treated as a dividend or distribution for income tax purposes or for any other reasons. We may only make such a discretionary adjustment if we make the same proportionate adjustment to each fixed settlement rate.
Adjustments to the fixed settlement rates will be calculated to the nearest ten thousandth of a share. No adjustment to the fixed settlement rates will be required unless the adjustment would require an increase or decrease of at least one percent in one or both fixed settlement rates. If any adjustment is not required to be made because it would not change one or both fixed settlement rates by at least one percent, then the adjustment will be carried forward and taken into account in any subsequent adjustment. All anti-dilution adjustments will be made not later than each day of any market value averaging period and the time at which we are otherwise required to determine the relevant settlement rate or amount of make-whole shares (if applicable) in connection with any settlement with respect to the purchase contracts.
No adjustment to the fixed settlement rates will be made if holders of Equity Units participate, as a result of holding the Equity Units and without having to settle the purchase contracts that form part of the Equity Units, in the transaction that would otherwise give rise to an adjustment as if they held a number of shares of our common stock equal to the maximum settlement rate, at the same time and upon the same terms as the holders of common stock participate in the transaction.
The fixed settlement rates will not be adjusted (subject to our right to increase them if our board of directors deems it advisable as described in the third preceding paragraph):
•upon the issuance of any shares of our common stock pursuant to any present or future plan providing for the reinvestment of dividends or interest payable on our securities
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and the investment of additional optional amounts in shares of our common stock under any plan;
•upon the issuance of options, restricted stock or other awards in connection with any employment contract, executive compensation plan, benefit plan or other similar arrangement with or for the benefit of any one or more employees, officers, directors, consultants or independent contractors or the exercise of such options or other awards;
•upon the issuance of any shares of our common stock pursuant to any option, warrant, right or exercisable, exchangeable or convertible security outstanding as of the date the Equity Units were first issued;
•for a change in the par value or no par value of the common stock; or
•for accumulated and unpaid contract adjustment payments.
We will, as promptly as practicable after the fixed settlement rate is adjusted, provide written notice of the adjustment to the holders of Equity Units.
If an adjustment is made to the fixed settlement rates, an adjustment also will be made to the reference price and the threshold appreciation price on an inversely proportional basis solely to determine which of the clauses of the definition of settlement rate will be applicable to determine the settlement rate with respect to the purchase contract settlement date or any fundamental change early settlement date.
If any adjustment to the fixed settlement rates becomes effective, or any effective date, expiration time, ex-date or record date for any stock split or reverse stock split, tender or exchange offer, issuance, dividend or distribution (relating to a required fixed settlement rate adjustment) occurs, during the period beginning on, and including, (1) the open of business on a first trading day of the 20 scheduled trading-day period during which the applicable market value is calculated or (2) in the case of the optional early settlement or fundamental change early settlement, the relevant early settlement date or the date on which the fundamental change early settlement right is exercised and, in each case, ending on, and including, the date on which we deliver shares of our common stock under the related purchase contract, we will make appropriate adjustments to the fixed settlement rates and/or the number of shares of our common stock deliverable upon settlement with respect to the purchase contract, in each case, consistent with the methodology used to determine the anti-dilution adjustments set forth above. If any adjustment to the fixed settlement rates becomes effective, or any effective date, expiration time, ex-date or record date for any stock split or reverse stock split, tender or exchange offer, issuance, dividend or distribution (relating to a required fixed settlement rate adjustment) occurs, during the period used to determine the “stock price” or any other averaging period hereunder, we will make appropriate adjustments to the applicable prices, consistent with the methodology used to determine the anti-dilution adjustments set forth above.
Reorganization Events
The following events are defined as “reorganization events”:
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•any consolidation or merger of the Company with or into another person or of another person with or into the Company or a similar transaction (other than a consolidation, merger or similar transaction in which the Company is the continuing corporation and in which the shares of our common stock outstanding immediately prior to the merger or consolidation are not exchanged for cash, securities or other property of the Company or another person);
•any sale, transfer, lease or conveyance to another person of the property of the Company as an entirety or substantially as an entirety, as a result of which the shares of our common stock are exchanged for cash, securities or other property;
•any statutory exchange of the common stock of the Company with another corporation (other than in connection with a merger or acquisition); and
•any liquidation, dissolution or termination of the Company (other than as a result of or after the occurrence of a termination event described below under “—Termination”).
Following the effective date of a reorganization event, the settlement rate shall be determined by reference to the value of an exchange property unit, and we shall deliver, upon settlement of any purchase contract, a number of exchange property units equal to the number of shares of our common stock that we would otherwise be required to deliver. An “exchange property unit” is the kind and amount of common stock, other securities, other property or assets (including cash or any combination thereof) receivable in such reorganization event (without any interest thereon, and without any right to dividends or distribution thereon which have a record date that is prior to the applicable settlement date) per share of our common stock by a holder of common stock that is not a person with which we are consolidated or into which we are merged or which merged into us or to which such sale or transfer was made, as the case may be (we refer to any such person as a “constituent person”), or an affiliate of a constituent person, to the extent such reorganization event provides for different treatment of common stock held by the constituent person and/or the affiliates of the constituent person, on the one hand, and non-affiliates of a constituent person, on the other hand. In the event holders of our common stock (other than any constituent person or affiliate thereof) have the opportunity to elect the form of consideration to be received in such transaction, the exchange property unit that holders of the Corporate Units or Treasury Units are entitled to receive will be deemed to be (1) the weighted average of the types and amounts of consideration received by the holders of our common stock that affirmatively make an election or (2) if no holders of our common stock affirmatively make such an election, the types and amounts of consideration actually received by the holders of our common stock.
In the event of such a reorganization event, the person formed by such consolidation or merger or the person which acquires our assets shall execute and deliver to the purchase contract agent an agreement providing that the holder of each Equity Unit that remains outstanding after the reorganization event (if any) shall have the rights described in the preceding paragraph. Such supplemental agreement shall provide for adjustments to the amount of any securities constituting all or a portion of an exchange property unit and/or adjustments to the fixed settlement rates, which, for events subsequent to the effective date of such reorganization event, shall be as nearly equivalent as may be practicable to the adjustments provided for under “—Anti-dilution Adjustments” above. The provisions described in the preceding two paragraphs shall similarly apply to successive reorganization events.
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In connection with any reorganization event, we will also adjust the reference dividend based on the number of shares of common stock comprising an exchange property unit and (if applicable) the value of any non-stock consideration comprising an exchange property unit. If an exchange property unit is composed solely of non-stock consideration, the reference dividend will be zero.
Termination
The purchase contract and pledge agreement provides that the purchase contracts and the obligations and rights of us and of the holders of Corporate Units and Treasury Units thereunder (including the holders’ obligation and right to purchase and receive shares of our common stock and to receive accrued and unpaid contract adjustment payments, including deferred contract adjustment payments and compounded contract adjustment payments thereon) will immediately and automatically terminate upon the occurrence of a termination event (as defined below).
Upon any termination event, the Equity Units will represent the right to receive the Notes underlying the undivided beneficial interest in the Notes, applicable ownership interests in the Treasury Portfolio, or the Treasury securities, as the case may be, forming part of such Equity Units. Upon the occurrence of a termination event, we will promptly give the purchase contract agent, the collateral agent and the holders notice of such termination event and the collateral agent will release the related interests in the Notes, applicable ownership interests in the Treasury portfolio or Treasury securities, as the case may be, from the pledge arrangement and transfer such interests in the Notes, applicable ownership interests in the Treasury portfolio or Treasury securities to the purchase contract agent for distribution to the holders of Corporate Units and Treasury Units. If a holder is entitled to receive Notes in an aggregate principal amount that is not an integral multiple of $1,000, the purchase contract agent may request that we issue Notes in denominations of $50.00 and integral multiples thereof in exchange for Notes in denominations of $1,000 or integral multiples thereof. In addition, if any holder is entitled to receive, with respect to its applicable ownership interests in the Treasury portfolio or its pledged Treasury securities, any securities having a principal amount at maturity of less than $1,000, the purchase contract agent will dispose of such securities for cash and pay the cash received to the holder in lieu of such applicable ownership in the Treasury portfolio or such Treasury securities. Upon any termination event, however, such release and distribution may be subject to a delay. In the event that the Company becomes the subject of a case under the U.S. Bankruptcy Code, such delay may occur as a result of the automatic stay under the U.S. Bankruptcy Code and continue until such automatic stay has been lifted. Moreover, claims arising out of the Notes will be subject to the equitable jurisdiction and powers of the bankruptcy court.
A “termination event” means any of the following events with respect to the Company:
(1)at any time on or prior to the purchase contract settlement date, a decree or order by a court having jurisdiction in the premises shall have been entered adjudicating the Company a bankrupt or insolvent, or approving as properly filed a petition seeking reorganization arrangement, adjustment or composition of or in respect of the Company under the U.S. Bankruptcy Code or any other similar applicable federal or state law and such decree or order shall have been entered more than 90 days prior to the purchase contract settlement date and shall have continued undischarged and unstayed for a period of 90 consecutive days;
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(2)at any time on or prior to the purchase contract settlement date, a decree or order of a court having jurisdiction in the premises shall have been entered for the appointment of a receiver, liquidator, trustee, assignee, sequestrator or other similar official in bankruptcy or insolvency of the Company or of all or any substantial part of the Company’s property, or for the winding up or liquidation of the Company’s affairs, and such decree or order shall have been entered more than 90 days prior to the purchase contract settlement date and shall have continued undischarged and unstayed for a period of 90 consecutive days; or
(3)at any time on or prior to the purchase contract settlement date, the Company shall institute proceedings to be adjudicated a bankrupt or insolvent, or shall consent to the institution of bankruptcy or insolvency proceedings against it, or shall file a petition or answer or consent seeking reorganization under the U.S. Bankruptcy Code or any other similar applicable federal or state law, or shall consent to the filing of any such petition, or shall consent to the appointment of a receiver, liquidator, trustee, assignee, sequestrator or other similar official of the Company or of all or any substantial part of the Company’s property, or shall make an assignment for the benefit of creditors, or shall admit in writing its inability to pay its debts generally as they become due.
Pledged Securities and Pledge
The undivided beneficial ownership interests in the Notes, or, following a successful optional remarketing, the applicable ownership interests in the Treasury portfolio (as described under the first bullet of the definition of “Treasury portfolio”), that are a component of the Corporate Units or, if substituted, the beneficial ownership interest in the Treasury securities that are a component of the Treasury Units, collectively, the “pledged securities,” will be pledged to the collateral agent for our benefit pursuant to the purchase contract and pledge agreement to secure your obligation to purchase shares of our common stock under the related purchase contracts. The rights of the holders of the Corporate Units and Treasury Units with respect to the pledged securities will be subject to our security interest therein. No holder of Corporate Units or Treasury Units will be permitted to withdraw the pledged securities related to such Corporate Units or Treasury Units from the pledge arrangement except:
•in the case of Corporate Units, to substitute a Treasury security for the related Note, as provided under “Description of the Equity Units—Creating Treasury Units by Substituting a Treasury Security for a Note;”
•in the case of Treasury Units, to substitute a Note for the related Treasury security, as provided under “Description of the Equity Units—Recreating Corporate Units;” and
•upon early settlement, settlement through the payment of separate cash or termination of the related purchase contracts.
Subject to our security interest and the terms of the purchase contract and pledge agreement, each holder of a Corporate Unit (unless the Treasury portfolio has replaced the Notes as a component of the Corporate Unit), will be entitled through the purchase contract agent and the collateral agent to all of the proportional rights and preferences of the related Notes (including distribution, voting, redemption, repayment and liquidation rights). Each holder of Treasury Units
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and each holder of Corporate Units (if the Treasury portfolio has replaced the Notes as a component of the Corporate Units), will retain beneficial ownership of the related Treasury securities or the applicable ownership interests in the Treasury portfolio, as applicable, pledged in respect of the related purchase contracts. We will have no interest in the pledged securities other than our security interest.
Except as described in “Certain Provisions of the Purchase Contract and Pledge Agreement—General,” upon receipt of distributions on the pledged securities, the collateral agent will distribute such payments to the purchase contract agent, which in turn will distribute those payments to the holders in whose names the Corporate Units or Treasury Units are registered at the close of business on the record date for the distribution.

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CERTAIN PROVISIONS OF THE PURCHASE CONTRACT AND PLEDGE
AGREEMENT

In this Description of the Purchase Contract and Pledge Agreement, “AEP,” “we,” “us,” “our” and the “Company” refer only to American Electric Power Company, Inc. and any successor obligor, and not to any of its subsidiaries.
The following is a summary of some of the other terms of the purchase contract and pledge agreement. The summary contains a description of additional material terms of the agreement but is only a summary and is not complete. This summary is subject to and is qualified by reference to all the provisions of the purchase contract and pledge agreement, including the definitions of certain terms used therein, the form of which has been or will be filed and incorporated by reference as an exhibit to the registration statement of which this prospectus supplement and the accompanying base prospectus form a part.
General
Except as described under “—Book-Entry System” in the accompanying prospectus, payments on the Corporate Units and Treasury Units will be payable, the purchase contracts will be settled, and transfers of the Corporate Units and Treasury Units will be registrable at, the office of the purchase contract agent or its agent, in each case, in the Borough of Manhattan, The City of New York. In addition, if the Corporate Units or Treasury Units do not remain in book-entry form, we will make payments on the Corporate Units and Treasury Units by check mailed to the address of the person entitled thereto as shown on the security register or by a wire transfer to the account designated by the holder by a prior written notice.
Shares of common stock will be delivered on the purchase contract settlement date (or earlier upon early settlement), or, if the purchase contracts have terminated, the related pledged securities will be delivered (subject to delays, including potentially as a result of the imposition of the automatic stay under the U.S. Bankruptcy Code, as described under “Description of the Purchase Contracts—Termination”) at the office of the purchase contract agent or its agent upon presentation and surrender of the applicable Corporate Unit or Treasury Unit certificate, if in certificated form.
If Corporate Units or Treasury Units are in certificated form and the holder fails to present and surrender the certificate evidencing the Corporate Units or Treasury Units to the purchase contract agent on or prior to the purchase contract settlement date, the shares of common stock issuable upon settlement with respect to the related purchase contract will be registered in the name of the purchase contract agent or its nominee. The shares, together with any distributions, will be held by the purchase contract agent as agent for the benefit of the holder until the certificate is presented and surrendered or the holder provides satisfactory evidence that the certificate has been destroyed, lost or stolen, together with any indemnity that may be required by the purchase contract agent and us.
If the purchase contracts terminate prior to the purchase contract settlement date, the related pledged securities are transferred to the purchase contract agent for distribution to the holders, and a holder fails to present and surrender the certificate evidencing the holder’s Corporate Units or Treasury Units, if in certificated form, to the purchase contract agent, the related pledged securities
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delivered to the purchase contract agent and payments on the pledged securities will be held by the purchase contract agent as agent for the benefit of the holder until the applicable certificate is presented, if in certificated form, or the holder provides the evidence and indemnity described above.
No service charge will be made for any registration of transfer or exchange of the Corporate Units or Treasury Units, except for any tax or other governmental charge that may be imposed in connection therewith.
The purchase contract agent will have no obligation to invest or to pay interest on any amounts it holds pending payment to any holder.
Modification
The purchase contract and pledge agreement will contain provisions permitting us, the purchase contract agent and the collateral agent, to modify the purchase contract and pledge agreement without the consent of the holders for any of the following purposes:
•to evidence the succession of another person to our obligations;
•to add to the covenants for the benefit of holders or to surrender any of our rights or powers under the purchase contract and pledge agreement;
•to evidence and provide for the acceptance of appointment of a successor purchase contract agent or a successor collateral agent or securities intermediary;
•to make provision with respect to the rights of holders pursuant to the requirements applicable to reorganization events;
•to cure any ambiguity or to correct or supplement any provisions that may be inconsistent with any other provision in the purchase contract and pledge agreement;
•to make such other provisions in regard to matters or questions arising under the purchase contract and pledge agreement that do not materially and adversely affect the rights of any holders of Equity Units; and
•to conform the provisions of the purchase contract and pledge agreement to the description of such agreement, the Equity Units and the purchase contracts contained in the preliminary prospectus supplement for the Equity Units as supplemented and/or amended by the related pricing term sheet.
The purchase contract and pledge agreement will contain provisions allowing us, the purchase contract agent and the collateral agent, subject to certain limited exceptions, to modify the terms of the purchase contracts or the purchase contract and pledge agreement with the consent of the holders of not less than a majority of the outstanding Equity Units, with holders of Corporate Units and Treasury Units voting as a single class. However, no such modification may, without the consent of the holder of each outstanding purchase contract affected thereby:

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•subject to our right to defer contract adjustment payments, change any payment date;
•impair the holders’ right to institute suit for the enforcement of a purchase contract or payment of any contract adjustment payments (including compounded contract adjustment payments);
• except as required pursuant to any anti-dilution adjustment, reduce the number of shares of our common stock purchasable under a purchase contract, increase the purchase price of the shares of our common stock on settlement of any purchase contract, change the purchase contract settlement date or change the right to early settlement or fundamental change early settlement in a manner adverse to the rights of the holders or otherwise adversely affect the holder’s rights under any purchase contract, the purchase contract and pledge agreement or remarketing agreement in any respect;
•increase the amount or change the type of collateral required to be pledged to secure a holder’s obligations under the purchase contract and pledge agreement;
•impair the right of the holder of any purchase contract to receive distributions on the collateral, or otherwise adversely affect the holder’s rights in or to such collateral;
•reduce any contract adjustment payments or any deferred contract adjustment payments (including compounded contract adjustment payments) or change any place where, or the coin or currency in which, any contract adjustment payment is payable; or
•reduce the percentage of the outstanding purchase contracts whose holders’ consent is required for the modification, amendment or waiver of the provisions of the purchase contracts and the purchase contract and pledge agreement.
However, if any amendment or proposal would adversely affect only the Corporate Units or only the Treasury Units, then only the affected class of holders will be entitled to vote on such amendment or proposal, and such amendment or proposal will not be effective except with the consent of the holders of not less than a majority of such class or, if referred to in the seven bullets above, each holder affected thereby.
No Consent to Assumption
Each holder of a Corporate Unit or a Treasury Unit will be deemed under the terms of the purchase contract and pledge agreement, by the purchase of such Corporate Unit or Treasury Unit, to have expressly withheld any consent to the assumption under Section 365 of the U.S. Bankruptcy Code or otherwise, of the related purchase contracts by us, our receiver, liquidator or trustee or person or entity performing similar functions in the event that we become a debtor under the U.S. Bankruptcy Code or other similar state or federal law providing for reorganization or liquidation.

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Consolidation, Merger and Conveyance of Assets as an Entirety
We will agree not to consolidate with or merge into any other person or convey, transfer or lease our properties and assets substantially as an entirety to any person unless (1) the person formed by such consolidation or into which we merge or the person which acquires by conveyance or transfer, or which leases, our property and assets, substantially as an entirety, is a person organized and existing under the laws of the United States, any state thereof or the District of Columbia, and expressly assumes all of our responsibilities and liabilities under the purchase contracts, the Corporate Units, the Treasury Units, the purchase contract and pledge agreement, the remarketing agreement (if any) and the indenture by one or more supplemental agreements in form satisfactory to the purchase contract agent, the collateral agent and the notes trustee, executed and delivered to the purchase contract agent, the collateral agent and the notes trustee by such corporation, and (2) we or such successor corporation, as the case may be, will not, immediately after such merger or consolidation, or such sale or conveyance, be in default in the performance of any of its obligations or covenants under such agreements.
In case of any such consolidation, merger, sale or conveyance, and upon any such assumption by the successor corporation, such successor corporation shall succeed to and be substituted for us, with the same effect as if it had been named in the purchase contracts, the Corporate Units, the Treasury Units, the purchase contract and pledge agreement and the remarketing agreement (if any) as us and (other than in the case of a lease) we shall be relieved of any further obligation under the purchase contracts, the Corporate Units, the Treasury Units, the purchase contract and pledge agreement and the remarketing agreement (if any).
Title
We, the purchase contract agent and the collateral agent may treat the registered owner of any Corporate Units or Treasury Units as the absolute owner of the Corporate Units or Treasury Units for the purpose of making payment (subject to the record date provisions described above), settling the related purchase contracts and for all other purposes.
Replacement of Equity Unit Certificates
In the event that physical certificates have been issued, any mutilated Corporate Unit or Treasury Unit certificate will be replaced by us at the expense of the holder upon surrender of the certificate to the purchase contract agent at the corporate trust office of the purchase contract agent or its agent, in each case, in the Borough of Manhattan, The City of New York. Corporate Unit or Treasury Unit certificates that become destroyed, lost or stolen will be replaced by us at the expense of the holder upon delivery to us and the purchase contract agent of evidence of their destruction, loss or theft satisfactory to us and the purchase contract agent. In the case of a destroyed, lost or stolen Corporate Unit or Treasury Unit certificate, an indemnity satisfactory to the purchase contract agent and us may be required at the expense of the holder before a replacement certificate will be issued.
Notwithstanding the foregoing, we will not be obligated to issue any Corporate Unit or Treasury Unit certificates on or after the business day immediately preceding the purchase contract settlement date or the date on which the purchase contracts have terminated. The purchase contract and pledge agreement will provide that, in lieu of the delivery of a replacement Corporate Unit or
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Treasury Unit certificate, the purchase contract agent, upon delivery of the evidence and indemnity described above, will, in the case of the purchase contract settlement date, deliver the shares of common stock issuable pursuant to the purchase contracts included in the Corporate Units or Treasury Units evidenced by the certificate, or, if the purchase contracts have terminated prior to the purchase contract settlement date, transfer the pledged securities included in the Corporate Units or Treasury Units evidenced by the certificate.
Governing Law
The purchase contracts and the purchase contract and pledge agreement and the remarketing agreement will be governed by, and construed in accordance with, the laws of the State of New York.
Information Concerning the Purchase Contract Agent
The Bank of New York Mellon Trust Company, N.A. (or its successor) will be the purchase contract agent. The purchase contract agent will act as the agent for the holders of Corporate Units and Treasury Units. The purchase contract agent will not be obligated to take any discretionary action in connection with a default under the terms of the Corporate Units, the Treasury Units or the purchase contract and pledge agreement.
The purchase contract and pledge agreement will contain provisions limiting the liability of the purchase contract agent. The purchase contract and pledge agreement also will contain provisions under which the purchase contract agent may resign or be replaced. Such resignation or replacement will be effective upon the appointment of a successor.
In addition to serving as the purchase contract agent, The Bank of New York Mellon Trust Company, N.A. will serve as the “notes trustee” for the Notes. We and certain of our affiliates maintain banking relationships with The Bank of New York Mellon Trust Company, N.A. or its affiliates. The Bank of New York Mellon Trust Company, N.A. also serves as trustee under our indentures under which we and certain of our affiliates have issued securities. The Bank of New York Mellon Trust Company, N.A. and its affiliates have purchased, and are likely to purchase in the future, our securities and securities of our affiliates.
Information Concerning the Collateral Agent
The Bank of New York Mellon Trust Company, N.A. (or its successor) will be the collateral agent. The collateral agent will act solely as our agent and will not assume any obligation or relationship of agency or trust for or with any of the holders of the Corporate Units and the Treasury Units except for the obligations owed by a pledgee of property to the owner thereof under the purchase contract and pledge agreement and applicable law.
The purchase contract and pledge agreement will contain provisions limiting the liability of the collateral agent. The purchase contract and pledge agreement also will contain provisions under which the collateral agent may resign or be replaced. Such resignation or replacement will be effective upon the appointment of a successor.

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In addition to serving as the collateral agent, The Bank of New York Mellon Trust Company, N.A. will serve as the “notes trustee” for the Notes. We and certain of our affiliates maintain banking relationships with The Bank of New York Mellon Trust Company, N.A. or its affiliates. The Bank of New York Mellon Trust Company, N.A. also serves as trustee under our indentures under which we and certain of our affiliates have issued securities. The Bank of New York Mellon Trust Company, N.A. and its affiliates have purchased, and are likely to purchase in the future, our securities and securities of our affiliates.
Miscellaneous
The purchase contract and pledge agreement will provide that we will, at all times prior to the purchase contract settlement date, reserve and keep available, free from preemptive rights, out of our authorized but unissued common stock the maximum number of shares of our common stock issuable against payment (including the maximum number of make-whole shares issuable upon a fundamental change early settlement) in respect of all purchase contracts included in the Corporate Units or Treasury Units evidenced by the outstanding certificates.
The purchase contract and pledge agreement will provide that we will pay all fees and expenses related to (1) the retention of the purchase contract agent, the collateral agent, the custodial agent and the securities intermediary and (2) any enforcement by the purchase contract agent of the rights of the holders of the Corporate Units and Treasury Units. Holders who elect to substitute the related pledged securities, thereby creating Treasury Units or recreating Corporate Units, however, will be responsible for any fees or expenses payable in connection with such substitution, as well as for any commissions, fees or other expenses incurred in acquiring the pledged securities to be substituted. We will not be responsible for any such fees or expenses. The purchase contract agent shall be under no obligation to exercise any of the rights or powers vested in it by the purchase contract and pledge agreement at the request or direction of any of the holders pursuant to the purchase contract and pledge agreement, unless such holders shall have offered to the purchase contract agent security or indemnity reasonably satisfactory to the purchase contract agent against the costs, expenses and liabilities which might be incurred by it in compliance with such request or direction.
The purchase contract and pledge agreement will also provide that any court of competent jurisdiction may in its discretion require, in any suit for the enforcement of any right or remedy under the purchase contract and pledge agreement, or in any suit against the purchase contract agent for any action taken, suffered or omitted by it as purchase contract agent, the filing by any party litigant in such suit of an undertaking to pay the costs of such suit, and that such court may in its discretion assess reasonable costs, including reasonable attorneys’ fees and costs against any party litigant in such suit, having due regard to the merits and good faith of the claims or defenses made by such party litigant. The foregoing shall not apply to any suit instituted by the purchase contract agent, to any suit instituted by any holder, or group of holders, holding in the aggregate more than 10% of the outstanding Equity Units, or to any suit instituted by any holder for the enforcement of any interest on any Notes owed pursuant to such holder’s applicable ownership interests in Notes or contract adjustment payments on or after the respective payment date therefor in respect of any Equity Unit held by such holder, or for enforcement of the right to purchase shares of our common stock under the purchase contracts constituting part of any Equity Unit held by such holder.
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Exhibit 4(d)

EXECUTION VERSION

U.S. $500,000,000

CREDIT AGREEMENT

Dated as of January 19, 2021

among

PUBLIC SERVICE COMPANY OF OKLAHOMA

as the Borrower

THE LENDERS NAMED HEREIN
as Initial Lenders

and

SUMITOMO MITSUI BANKING CORPORATION
as Administrative Agent

	

SUMITOMO MITSUI BANKING CORPORATION
WELLS FARGO BANK, NATIONAL ASSOCIATION
PNC CAPITAL MARKETS LLC
KEYBANC CAPITAL MARKETS INC.
CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK
as Joint Lead Arrangers and Joint Bookrunners

TABLE OF CONTENTS

	Page	
Article I DEFINITIONS AND ACCOUNTING TERMS	1	
		
Section 1.01    Certain Defined Terms.	1	
Section 1.02    Computation of Time Periods.	17	
Section 1.03    Accounting Terms.	17	
Section 1.04    Other Interpretive Provisions.	18	
Section 1.05    Divisions.	18	
		
Article II AMOUNTS AND TERMS OF THE ADVANCES	18	
		
Section 2.01    The Advances.	18	
Section 2.02    Making the Advances.	19	
Section 2.03    Fees.	20	
Section 2.04    Termination or Reduction of the Commitments.	20	
Section 2.05    Repayment of Advances.	21	
Section 2.06    Evidence of Indebtedness.	21	
Section 2.07    Interest on Advances.	22	
Section 2.08    Interest Rate Determination.	22	
Section 2.09    Optional Conversion of Advances.	23	
Section 2.10    Optional Prepayments of Advances.	23	
Section 2.11    Increased Costs.	24	
Section 2.12    Illegality.	25	
Section 2.13    Payments and Computations.	25	
Section 2.14    Taxes.	26	
Section 2.15    Mitigation Obligations; Replacement of Lenders.	30	
Section 2.16    Sharing of Payments, Etc.	31	
		
Article III CONDITIONS PRECEDENT	32	
		
Section 3.01    Conditions Precedent to the Closing Date and Initial Advances.	32	
Section 3.02    Conditions Precedent to each Advance.	33	
		
Article IV REPRESENTATIONS AND WARRANTIES	34	
		
Section 4.01    Representations and Warranties of the Borrower.	34	
		
Article V COVENANTS OF THE BORROWER	37	
		
Section 5.01    Affirmative Covenants.	37	
Section 5.02    Negative Covenants.	40	
Section 5.03    Financial Covenant.	42	
		
Article VI EVENTS OF DEFAULT	42	

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Section 6.01    Events of Default.	42	
		
Article VII THE ADMINISTRATIVE AGENT	44	
		
Section 7.01    Appointment and Authorization.	44	
Section 7.02    Administrative Agent and Affiliates.	44	
Section 7.03    Action by Administrative Agent.	44	
Section 7.04    Consultation with Experts.	45	
Section 7.05    Liability of Administrative Agent.	45	
Section 7.06    Indemnification.	45	
Section 7.07    Right to Request and Act on Instructions.	46	
Section 7.08    Credit Decision.	47	
Section 7.09    Notice of Default.	47	
Section 7.10    Successor Administrative Agent.	47	
Section 7.11    Return of Payments.	48	
Section 7.12    Defaulting Lenders.	48	
Section 7.13    Sharing of Payments	48	
Section 7.14    Right to Perform, Preserve and Protect.	49	
Section 7.15    Additional Titled Agents.	49	
		
Article VIII MISCELLANEOUS	49	
		
Section 8.01    Amendments, Etc.	49	
Section 8.02    Notices, Etc.	50	
Section 8.03    No Waiver; Remedies.	52	
Section 8.04    Costs and Expenses.	52	
Section 8.05    Right of Set-off.	54	
Section 8.06    Binding Effect.	55	
Section 8.07    Assignments and Participations.	55	
Section 8.08    Confidentiality.	59	
Section 8.09    Governing Law.	59	
Section 8.10    Severability.	60	
Section 8.11    Execution in Counterparts.	60	
Section 8.12    Jurisdiction, Etc.	60	
Section 8.13    Waiver of Jury Trial.	61	
Section 8.14    USA Patriot Act.	61	
Section 8.15    No Fiduciary Duty.	62	
Section 8.16    Defaulting Lenders.	62	
Section 8.17    Acknowledgment and Consent to Bail-In of EEA Financial Institutions.	64	
Section 8.18    Interest Rate Limitation.		
Section 8.19    Certain ERISA Matters.	65	
Section 8.20    Eurodollar Rate Notification.	66	
Section 8.21    Successor Eurodollar Rate Index	66	

EXHIBITS AND SCHEDULES

EXHIBIT A	------	Form of Notice of Borrowing	

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EXHIBIT B	------	Form of Assignment and Assumption	
EXHIBIT C-1	------	Form of U.S. Tax Compliance Certificate (For Foreign Lenders	
		That Are Not Partnerships For U.S. Federal Income Tax Purposes)	
EXHIBIT C-2	------	Form of U.S. Tax Compliance Certificate (For Foreign Participants	
		That Are Not Partnerships For U.S. Federal Income Tax Purposes)	
EXHIBIT C-3	------	Form of U.S. Tax Compliance Certificate (For Foreign Participants	
		That Are Partnerships For U.S. Federal Income Tax Purposes)	
EXHIBIT C-4	------	Form of U.S. Tax Compliance Certificate (For Foreign Lenders	
	------	That Are Partnerships For U.S. Federal Income Tax Purposes)	
EXHIBIT D	------	Form of Notice of Conversion	
SCHEDULE I	------	Schedule of Initial Lenders	
SCHEDULE 4.01(m)	------	Schedule of Significant Subsidiaries	

CREDIT AGREEMENT
CREDIT AGREEMENT, dated as of January 19, 2021 (this “Agreement”), between PUBLIC SERVICE COMPANY OF OKLAHOMA, an Oklahoma corporation (the “Borrower”), the banks, financial institutions and other institutional lenders listed on the signatures pages hereof (the “Initial Lenders”), and SUMITOMO MITSUI BANKING CORPORATION (“SMBC”), as administrative agent (in such capacity, and together with its successors appointed pursuant to the terms of this Agreement, the “Administrative Agent”) for the Lenders (as hereinafter defined).
ARTICLE I
DEFINITIONS AND ACCOUNTING TERMS

SECTION 1.01    Certain Defined Terms.

As used in this Agreement, the following terms shall have the following meanings (such meanings to be equally applicable to both the singular and plural forms of the terms defined):
“Act” has the meaning specified in Section 4.01(l).
“Administrative Agent” has the meaning specified in the recital of parties to this Agreement.
“Administrative Questionnaire” means an administrative questionnaire in a form supplied by the Administrative Agent.
“Advance” means an advance by a Lender to a Borrower as part of a Borrowing and refers to a Base Rate Advance or a Eurodollar Rate Advance.
“AEP” means American Electric Power Company, Inc., a New York corporation.
“Affected Financial Institution” means (a) any EEA Financial Institution or (b) any UK Financial Institution.
“Affiliate” means, as to any Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with such Person or is a director or officer of such Person. For purposes of this definition, the term “control” (including the terms “controlling”, “controlled by” and “under common control with”) of a Person means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of Voting Stock, by contract or otherwise.
“Agent Parties” has the meaning specified in Section 8.02(c).
“Agent’s Account” means the account of the Administrative Agent designated by the Administrative Agent to the Lenders and the Borrower and maintained by the Administrative Agent at Sumitomo Mitsui Banking Corporation with its office at 277 Park Avenue, New York,

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New York 10172, or such other account of the Administrative Agent as the Administrative Agent may from time to time designate in a written notice to the Lenders and the Borrower.
“Anti-Corruption Laws” means all laws, rules, and regulations of any jurisdiction applicable to the Borrower or its Subsidiaries from time to time concerning or relating to bribery, money laundering or corruption.
“Applicable Law” means (i) all applicable common law and principles of equity and (ii) all applicable provisions of all (A) constitutions, statutes, rules, regulations and orders of Governmental Authorities, (B) Governmental Approvals and (C) orders, decisions, judgments and decrees of all courts (whether at law or in equity or admiralty) and arbitrators.
“Applicable Lending Office” means, with respect to each Lender, such Lender’s Domestic Lending Office in the case of a Base Rate Advance and such Lender’s Eurodollar Lending Office in the case of a Eurodollar Rate Advance.
“Applicable Margin” means a percentage, per annum, equal to (i) for Eurodollar Rate Advances, 0.80% and (ii) for Base Rate Advances, 0.00%; provided, that the Applicable Margin shall be increased, upon the occurrence and during the continuance of any Event Default, by 2.00% per annum.
“Approved Fund” means any Fund that is administered or managed by (i) a Lender, (ii) an Affiliate of a Lender or (iii) an entity or an Affiliate of an entity that administers or manages a Lender.
“Arrangers” means, collectively, SMBC, Wells Fargo Bank, National Association, PNC Capital Markets LLC, KeyBanc Capital Markets Inc. and Credit Agricole Corporate and Investment Bank, in their capacities as joint lead arrangers and joint bookrunners of the Facility.
“Assignment and Assumption” means an assignment and assumption entered into by a Lender and an Eligible Assignee (with the consent of any party whose consent is required by Section 8.07), and accepted by the Administrative Agent, in substantially the form of Exhibit B hereto or any other form approved by the Administrative Agent.
“Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable Resolution Authority in respect of any liability of an Affected Financial Institution.
“Bail-In Legislation” means (a) with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law, regulation rule or requirement for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule and (b) with respect to the United Kingdom, Part I of the United Kingdom Banking Act 2009 (as amended from time to time) and any other law, regulation or rule applicable in the United Kingdom relating to the resolution of unsound or failing banks, investment firms or other financial institutions or their affiliates (other than through liquidation, administration or other insolvency proceedings).
“Bankruptcy Event” means, with respect to any Person, such Person becomes the subject of a proceeding under any Debtor Relief Law, or has had a receiver, custodian, conservator, trustee,

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administrator, assignee for the benefit of creditors or similar Person charged with reorganization or liquidation of its business or assets (including the Federal Deposit Insurance Corporation or any other Governmental Authority acting in a similar capacity) appointed for it, or, in the good faith determination of the Administrative Agent, has taken any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any such proceeding or appointment; provided that, a Bankruptcy Event shall not result solely by virtue of any ownership interest, or acquisition of any equity interest, in such Person by a Governmental Authority so long as such ownership interest does not result in or provide such Person with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Person (or such Governmental Authority) to reject, repudiate, disavow or disaffirm obligations under any agreement in which it commits to extend credit.
“Base Rate” means a fluctuating interest rate per annum in effect from time to time, which rate per annum shall at all times be equal to the highest of the following rates then in effect:
(i)    the rate of interest established by the Administrative Agent from time to time as the Administrative Agent’s prime rate;
(ii)    1/2 of 1% per annum above the Federal Funds Rate;
(iii)    the rate of interest per annum equal to the Eurodollar Rate as determined on such day (or if such day is not a Business Day, on the next preceding Business Day) that would be applicable to a Eurodollar Rate Advance having an Interest Period of one month, plus 1%; and
(iv)    0%.
“Base Rate Advance” means an Advance that bears interest as provided in Section 2.07(a).
“Beneficial Ownership Certification” means a certification regarding beneficial ownership as required by the Beneficial Ownership Regulation.
“Beneficial Ownership Regulation” means 31 C.F.R. § 1010.230.
“Benefit Plan” means any of (i) an “employee benefit plan” (as defined in Section 3(3) of ERISA) that is subject to Title I of ERISA, (ii) a “plan” as defined in Section 4975 of the Code to which Section 4975 of the Code applies, and (iii) any Person whose assets include (for purposes of the Plan Asset Regulations or otherwise for purposes of Title I of ERISA or Section 4975 of the Code) the assets of any such “employee benefit plan” or “plan”.
“Borrower” has the meaning specified in the recital of parties to this Agreement.
“Borrowing” means a borrowing by the Borrower consisting of simultaneous Advances of the same Type, having the same Interest Period and ratably made or Converted on the same day by each of the Lenders pursuant to Section 2.02 or 2.09, as the case may be. All Advances to the Borrower of the same Type, having the same Interest Period and made or Converted on the same day shall be deemed a single Borrowing hereunder until repaid or next Converted.

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“Borrowing Date” means the date of any Borrowing.
“Business Day” means a day of the year on which banks are not required or authorized by law to close in New York City and, if the applicable Business Day relates to any Eurodollar Rate Advances, “Business Day” also includes a day on which dealings are carried out in the London interbank market.
“Change in Law” means the occurrence, after the date of this Agreement, of any of the following: (i) the adoption or taking effect of any law, rule, regulation or treaty, (ii) any change in any law, rule, regulation or treaty or in the administration, interpretation, implementation or application thereof by any Governmental Authority or (iii) the making or issuance of any request, rule, guideline or directive (whether or not having the force of law) by any Governmental Authority; provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change in Law”, regardless of the date enacted, implemented, adopted or issued.
“Charges” has the meaning specified in Section 8.18.
“Closing Date” means January 19, 2021.
“Commitment” means, for each Lender at any time on any day, the obligation of such Lender to make Advances to the Borrower in an aggregate amount no greater than the amount set forth on Schedule I hereto or, if such Lender has entered into any Assignment and Assumption, set forth for such Lender in the Register maintained by the Administrative Agent pursuant to Section 8.07(c), in each such case as such amount may be reduced from time to time pursuant to Section 2.04. The initial amount of each Lender’s Commitment as of the Closing Date is set forth on Schedule I hereto, or in the Assignment and Assumption pursuant to which such Lender shall have assumed its Commitment, as applicable.
“Commitment Fee Rate” means 0.10%.
“Commitment Percentage” means, as to any Lender as of any date of determination, the percentage describing such Lender’s pro rata share of the Commitments set forth in the Register from time to time; provided that in the case of Section 8.16 when a Defaulting Lender shall exist, “Commitment Percentage” means the percentage of the total Commitments (disregarding any Defaulting Lender’s Commitment) represented by such Lender’s Commitment. If the Commitments have terminated or expired, the Commitment Percentages shall be determined based upon the Commitments most recently in effect, giving effect to any assignments and to any Lender’s status as a Defaulting Lender at the time of determination.
“Commitment Period” has the meaning specified in Section 2.01.

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“Commitments” means, at any time on any day, the aggregate amount for all Lenders of each Lender’s Commitment then in effect hereunder. The initial amount of the Commitments hereunder on the Closing Date is $500,000,000.
“Communications” has the meaning specified in Section 8.02(b).
“Confidential Information” means information that the Borrower furnishes to the Administrative Agent, the Arrangers or any Lender in a writing designated as confidential, but does not include any such information that is or becomes generally available to the public or that is or becomes available to the Administrative Agent, the Arrangers or such Lender from a source other than the Borrower.
“Connection Income Taxes” means Other Connection Taxes that are imposed on or measured by overall gross receipts or income, or net income (however denominated) or that are franchise Taxes, privilege Taxes, license Taxes or branch profits Taxes.
“Consolidated Capital” means the sum of (i) Consolidated Debt of the Borrower and (ii) the consolidated equity of all classes of stock (whether common, preferred, mandatorily convertible preferred or preference) of the Borrower, in each case determined in accordance with GAAP, but including Equity-Preferred Securities issued by the Borrower and its Consolidated Subsidiaries and excluding the funded pension and other postretirement benefit plans, net of tax, components of accumulated other comprehensive income (loss).
“Consolidated Debt” of the Borrower means the total principal amount of all Debt described in clauses (i) through (v) of the definition of Debt and Guaranties of such Debt of the Borrower and its Consolidated Subsidiaries, excluding, however, (i) Debt of AEP Credit, Inc. that is non-recourse to the Borrower and its Consolidated Subsidiaries in respect of the sale of accounts receivable by the Borrower or its Consolidated Subsidiaries, (ii) Stranded Cost Recovery Bonds, and (iii) Equity-Preferred Securities not to exceed 10% of Consolidated Capital (calculated for purposes of this clause without reference to any Equity-Preferred Securities); provided that Guaranties of Debt included in the total principal amount of Consolidated Debt shall not be added to such total principal amount.
“Consolidated Subsidiary” means, with respect to any Person at any time, any Subsidiary or other Person the accounts of which would be consolidated with those of such first Person in its consolidated financial statements in accordance with GAAP.
“Consolidated Tangible Net Assets” means, on any date of determination and with respect to any Person at any time, the total of all assets (including revaluations thereof as a result of commercial appraisals, price level restatement or otherwise) appearing on the consolidated balance sheet of such Person and its Consolidated Subsidiaries most recently delivered to the Lenders pursuant to Section 5.01(i) as of such date of determination, net of applicable reserves and deductions, but excluding goodwill, trade names, trademarks, patents, unamortized debt discount and all other like intangible assets (which term shall not be construed to include such revaluations), less the aggregate of the consolidated current liabilities of such Person and its Consolidated Subsidiaries appearing on such balance sheet.

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“Convert”, “Conversion” and “Converted” each refers to a conversion of Advances of one Type into Advances of the other Type, or the selection of a new, or the renewal of the same, Interest Period for Eurodollar Rate Advances, pursuant to Section 2.08 or 2.09.
“Debt” of any Person means, without duplication, (i) all indebtedness of such Person for borrowed money, (ii) all obligations of such Person for the deferred purchase price of property or services (other than trade payables not overdue by more than 60 days incurred in the ordinary course of such Person’s business), (iii) all obligations of such Person evidenced by notes, bonds, debentures or other similar instruments, (iv) all obligations of such Person as lessee under leases that have been, in accordance with GAAP, recorded as capital leases, including, without limitation, the leases described in clause (iv) of Section 5.02(c), (v) all obligations of such Person in respect of reimbursement agreements with respect to acceptances, letters of credit (other than trade letters of credit) or similar extensions of credit, (vi) all Guaranties and (vii) all reasonably quantifiable obligations under indemnities or under support or capital contribution agreements, and other reasonably quantifiable obligations (contingent or otherwise) to purchase or otherwise to assure a creditor against loss in respect of, or to assure an obligee against loss in respect of, all Debt of others referred to in clauses (i) through (vi) above guaranteed directly or indirectly in any manner by such Person, or in effect guaranteed directly or indirectly by such Person through an agreement (A) to pay or purchase such Debt or to advance or supply funds for the payment or purchase of such Debt, (B) to purchase, sell or lease (as lessee or lessor) property, or to purchase or sell services, primarily for the purpose of enabling the debtor to make payment of such Debt or to assure the holder of such Debt against loss, (C) to supply funds to or in any other manner invest in the debtor (including any agreement to pay for property or services irrespective of whether such property is received or such services are rendered) or (D) otherwise to assure a creditor against loss.
“Debtor Relief Laws” means the Bankruptcy Code of the United States of America, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor relief laws of the United States or other applicable jurisdictions from time to time in effect.
“Default” means any Event of Default or any event that would constitute an Event of Default but for the requirement that notice be given or time elapse or both.
“Defaulting Lender” means, subject to Section 8.16(b), any Lender that (i) has failed to (A) fund all or any portion of its Advances within two Business Days of the date such Advances were required to be funded hereunder unless such Lender notifies the Administrative Agent and the Borrower in writing that such failure is the result of such Lender’s good faith determination that one or more conditions precedent to funding (each of which conditions precedent, together with any applicable Default, shall be specifically identified in such writing) has not been satisfied, or (B) pay to any Recipient any other amount required to be paid by it hereunder within two Business Days of the date when due, (ii) has notified the Borrower or any Recipient in writing that it does not intend to comply with its funding obligations hereunder or generally under other agreements in which it commits to extend credit, or has made a public statement to that effect (unless such writing or public statement relates to such Lender’s obligation to fund an Advance hereunder and states that such position is based on such Lender’s good faith determination that a condition precedent to funding (which condition precedent, together with any applicable Default,

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shall be specifically identified in such writing or public statement) cannot be satisfied), (iii) has failed, within three Business Days after written request by the Administrative Agent or the Borrower, to confirm in writing to the Administrative Agent and the Borrower that it will comply with its prospective funding obligations hereunder (provided that, such Lender shall cease to be a Defaulting Lender pursuant to this clause (iii) upon receipt of such written confirmation by the Administrative Agent and the Borrower), or (iv) has (A) become the subject of a Bankruptcy Event or (B) has, or has a direct or indirect parent company that has, become the subject of a Bail-In Action. Any determination by the Administrative Agent that a Lender is a Defaulting Lender under any one or more of clauses (i) through (iv) above shall be conclusive and binding absent manifest error, and such Lender shall be deemed to be a Defaulting Lender (subject to Section 8.16(b)) upon delivery of written notice of such determination to the Borrower and each Lender.
“Disclosure Documents” means (i) the Borrower’s Report on Form 10-K, as filed with the SEC, for the fiscal year ended December 31, 2019, (ii) the Borrower’s Quarterly Report on Form 10-Q, as filed with the SEC, for the period ended September 30, 2020 and (iii) the Borrower’s Current Reports on Form 8-K, as filed with the SEC after the date of filing the Borrower’s Quarterly Report on Form 10-Q for the periods ended March 31, 2020, June 30, 2020 and September 30, 2020 but prior to the Closing Date.
“Dollars” and the symbol “$” mean lawful currency of the United States of America.
“Domestic Lending Office” means, with respect to any Lender, the office of such Lender specified as its “Domestic Lending Office” on such Lender’s Administrative Questionnaire or in the Assignment and Assumption pursuant to which it became a Lender, or such other office of such Lender as such Lender may from time to time specify in writing to the Borrower and the Administrative Agent.
“EEA Financial Institution” means (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.
“EEA Member Country” means any of the member states of the European Union, Iceland, Liechtenstein, and Norway.
“EEA Resolution Authority” means any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.
“Eligible Assignee” means any Person that meets the requirements to be an assignee under Section 8.07(b)(iii), (v) and (vi) (subject to such consents, if any, as may be required under Section 8.07(b)(iii)).
“Engagement Letter” means the Engagement Letter, dated as of January 6, 2021, among the Borrower and SMBC, as may be amended, supplemented or otherwise modified.

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“Environmental Action” means any action, suit, demand, demand letter, claim, notice of non-compliance or violation, notice of liability or potential liability, investigation, proceeding, consent order or consent agreement relating in any way to any Environmental Law, Environmental Permit or Hazardous Materials or arising from alleged injury or threat of injury to health, safety or the environment, including, without limitation, (i) by any Governmental Authority for enforcement, cleanup, removal, response, remedial or other actions or damages and (ii) by any Governmental Authority or any third party for damages, contribution, indemnification, cost recovery, compensation or injunctive relief.
“Environmental Law” means any federal, state, local or foreign statute, law, ordinance, rule, regulation, code, order, judgment, decree or judicial or agency interpretation, policy or guidance relating to pollution or protection of the environment, health, safety or natural resources, including, without limitation, those relating to the use, handling, transportation, treatment, storage, disposal, release or discharge of Hazardous Materials.
“Environmental Permit” means any permit, approval, identification number, license or other authorization required under any Environmental Law.
“Equity-Preferred Securities” means, with respect to any Person at any time, (i) debt or preferred securities that are mandatorily convertible or mandatorily exchangeable into common shares of such Person and (ii) any other securities, however denominated, including but not limited to hybrid capital and trust originated preferred securities, (A) issued by such Person or any Consolidated Subsidiary of such Person, (B) that are not subject to mandatory redemption or the underlying securities, if any, of which are not subject to mandatory redemption, (C) that are perpetual or mature no less than 30 years from the date of issuance, (D) the indebtedness issued in connection with which, including any guaranty, is subordinate in right of payment to the unsecured and unsubordinated indebtedness of the issuer of such indebtedness or guaranty, and (E) the terms of which permit the deferral of the payment of interest or distributions thereon to a date occurring after the Termination Date.
“ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, and the regulations promulgated and rulings issued thereunder.
“ERISA Affiliate” means, with respect to any Person, each trade or business (whether or not incorporated) that is considered to be a single employer with such entity within the meaning of Section 414(b), (c), (m) or (o) of the Internal Revenue Code.
“ERISA Event” means (i) the termination of or withdrawal from any Plan by the Borrower or any of its ERISA Affiliates, (ii) the failure by the Borrower or any of its ERISA Affiliates to comply with ERISA or the related provisions of the Internal Revenue Code with respect to any Plan or (iii) the failure by the Borrower or any of its Subsidiaries to comply with Applicable Law with respect to any Foreign Plan.
“EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.
“Eurocurrency Liabilities” has the meaning assigned to that term in Regulation D of the Board of Governors of the Federal Reserve System, as in effect from time to time.

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“Eurodollar Lending Office” means, with respect to any Lender, the office of such Lender specified as its “Eurodollar Lending Office” on such Lender’s Administrative Questionnaire or in the Assignment and Assumption pursuant to which it became a Lender (or, if no such office is specified, its Domestic Lending Office), or such other office of such Lender as such Lender may from time to time specify in writing to the Borrower and the Administrative Agent.
“Eurodollar Rate” means, for any Interest Period for each Eurodollar Rate Advance comprising part of the same Borrowing, the interest rate per annum equal to the highest of: (i) 0% and (ii) the interest rate per annum determined by the Administrative Agent by dividing (the resulting quotient rounded upwards to the nearest 1/100th of 1% per annum) (A) the rate that appears on Bloomberg Page BBAM1 (or on such other substitute Bloomberg page that displays rates at which U.S. dollar deposits are offered by leading banks in the London interbank deposit market), or the rate that is quoted by another source selected by the Administrative Agent, reasonably acceptable to the Borrower, that has been approved by ICE Benchmark Association as an authorized information vendor for the purpose of displaying the rates at which U.S. dollar deposits are offered by leading banks in the London interbank deposit market (for purposes of this definition, an “Alternate Source”) at approximately 11:00 A.M., London time, two Business Days prior to the first day of such Interest Period as the London interbank offered rate for Dollars for an amount comparable to such Borrowing and having a Borrowing date and a maturity comparable to such Interest Period (or if there shall at any time, for any reason, no longer exist a Bloomberg Page BBAM1 (or any substitute page) or any Alternate Source, a comparable replacement rate determined by the Administrative Agent at such time (which determination shall be conclusive absent manifest error)), by (B) a number equal to 1.00 minus the percentage prescribed by the Federal Reserve Bank of New York for determining the maximum reserve requirements with respect to any Eurocurrency funding by banks from time to time; provided that if the Eurodollar Rate shall be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement.
“Eurodollar Rate Advance” means an Advance that bears interest as provided in Section 2.07(b).
“Eurodollar Rate Reserve Percentage” of any Lender for any Interest Period for each Eurodollar Rate Advance means the reserve percentage applicable to such Lender during such Interest Period (or if more than one such percentage shall be so applicable, the daily average of such percentages for those days in such Interest Period during which any such percentage shall be so applicable) under regulations issued from time to time by the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement (including, without limitation, any emergency, supplemental or other marginal reserve requirement) then applicable to such Lender with respect to liabilities or assets consisting of or including Eurocurrency Liabilities (or with respect to any other category of liabilities that includes deposits by reference to which the interest rate on Eurodollar Rate Advances is determined) having a term equal to such Interest Period.
“Events of Default” has the meaning specified in Section 6.01.
“Exchange Act” has the meaning specified in Section 6.01(f).

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“Excluded Tax” means any of the following Taxes imposed on or with respect to a Recipient or required to be withheld or deducted from a payment to a Recipient, (i) Taxes imposed on or measured by overall gross receipts or income, or net income (however denominated), franchise Taxes, privilege Taxes, license Taxes or branch profits Taxes, in each case, (A) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its Applicable Lending Office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (B) that are Other Connection Taxes, (ii) in the case of a Lender, U.S. federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in an Advance or Commitment pursuant to a law in effect on the date on which (A) such Lender acquires such interest in the Advance or Commitment (other than pursuant to an assignment request by the Borrower under Section 2.14(b)) or (B) such Lender changes its Applicable Lending Office, except in each case to the extent that, pursuant to Section 2.13, amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender became a party hereto or to such Lender immediately before it changed its Applicable Lending Office, (iii) Taxes attributable to such Recipient’s failure to comply with Section 2.13(g) and (iv) any U.S. federal withholding Taxes imposed under FATCA.
“Facility” means the aggregate commitment of the Lenders to make Advances to the Borrower hereunder up to a maximum of Five Hundred Million Dollars ($500,000,000), as such aggregate commitment may be reduced from time to time pursuant to Section 2.04.
“FATCA” means Sections 1471 through 1474 of the Internal Revenue Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof, any agreement entered into pursuant to Section 1471(b)(1) of the Internal Revenue Code, and any intergovernmental agreement entered into in connection with such sections of the Internal Revenue Code and any legislation, law, regulation or practice enacted or promulgated pursuant to such intergovernmental agreement.
“Federal Funds Rate” means, for any period, a fluctuating interest rate per annum (based on a year of 360 days and actual days elapsed and rounded upward to the nearest 1/100 of 1%) equal for each day during such period to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published for such day (or, if such day is not a Business Day, for the next preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average of the quotations for such day on such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it; provided that if the Federal Funds Rate as determined in accordance with this definition shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.
“Fee Letter” means the Fee Letter, dated as of January 6, 2021, among the Borrower and SMBC, as may be amended, supplemented or otherwise modified.
“Foreign Lender” means a Lender that is not a U.S. Person.

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“Foreign Plan” has the meaning specified in Section 4.01(i).
“Fund” means any Person (other than a natural Person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its activities.
“GAAP” has the meaning specified in Section 1.03.
“Governmental Approval” means any authorization, consent, approval, license or exemption of, registration or filing with, or report or notice to, any Governmental Authority.
“Governmental Authority” means the government of the United States of America or any other nation, or of any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra-national bodies such as the European Union or the European Central Bank).
“Guaranty” of any Person means any obligation, contingent or otherwise, of such Person (i) to pay any Debt of any other Person or (ii) incurred in connection with the issuance by a third person of a Guaranty of Debt of any other Person (whether such obligation arises by agreement to reimburse or indemnify such third Person or otherwise).
“Hazardous Materials” means (i) petroleum and petroleum products, byproducts or breakdown products, radioactive materials, asbestos-containing materials, polychlorinated biphenyls and radon gas and (ii) any other chemicals, materials or substances designated, classified or regulated as hazardous or toxic or as a pollutant or contaminant under any Environmental Law.
“Indemnified Party” has the meaning specified in Section 8.04(b).
“Indemnified Taxes” means (i) Taxes, other than Excluded Taxes, imposed on or with respect to any payment made by or on account of any obligation of the Borrower under any Loan Document and (ii) to the extent not otherwise described in clause (i), Other Taxes.
“Initial Lenders” has the meaning specified in the recital of parties to this Agreement.
“Interest Period” means, for each Eurodollar Rate Advance comprising part of the same Borrowing, the period commencing on the date of such Eurodollar Rate Advance or the date of the Conversion of any Base Rate Advance into such Eurodollar Rate Advance and ending on the last day of the period selected by the Borrower pursuant to the provisions below and, thereafter, with respect to Eurodollar Rate Advances, each subsequent period commencing on the last day of the immediately preceding Interest Period and ending on the last day of the period selected by the Borrower pursuant to the provisions below. The duration of each such Interest Period shall be one, two, three or six months, as the Borrower may, upon notice received by the Administrative Agent not later than 11:00 A.M. on the third Business Day prior to the first day of such Interest Period, select; provided, however, that:

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(i)    the Borrower may not select any Interest Period that ends after the Termination Date;
(ii)    Interest Periods commencing on the same date for Eurodollar Rate Advances comprising part of the same Borrowing shall be of the same duration;
(iii)    whenever the last day of any Interest Period would otherwise occur on a day other than a Business Day, the last day of such Interest Period shall be extended to occur on the next succeeding Business Day, provided, however, that, if such extension would cause the last day of such Interest Period to occur in the next following calendar month or on a date after the Termination Date, the last day of such Interest Period shall occur on the next preceding Business Day; and
(iv)    whenever the first day of any Interest Period occurs on a day of an initial calendar month for which there is no numerically corresponding day in the calendar month that succeeds such initial calendar month by the number of months equal to the number of months in such Interest Period, such Interest Period shall end on the last Business Day of such succeeding calendar month.
“Internal Revenue Code” means the Internal Revenue Code of 1986, as amended from time to time, and the regulations promulgated and rulings issued thereunder.
“IRS” means the United States Internal Revenue Service.
“Lenders” means the Initial Lenders and each other Person that shall become a party hereto pursuant to Section 8.07, in each case other than any such Person that shall have ceased to be a party hereto pursuant to Section 8.07.
“Lien” means any lien, security interest or other charge or encumbrance of any kind, or any other type of preferential arrangement, including, without limitation, the lien or retained security title of a conditional vendor and any easement, right of way or other encumbrance on title to real property.
“Loan Documents” means, collectively, (i) the Engagement Letter, (ii) the Fee Letter, (iii) this Agreement, and (iv) any promissory note issued pursuant to Section 2.06(d), in each case, as amended, supplemented or modified from time to time.
“Margin Regulations” means Regulations T, U and X of the Board of Governors of the Federal Reserve System, as in effect from time to time.
“Margin Stock” has the meaning specified in the Margin Regulations.
“Material Adverse Change” means any material adverse change (i) in the business, condition (financial or otherwise) or operations of the Borrower and its Subsidiaries, taken as a whole, or (ii) that is reasonably likely to affect the legality, validity or enforceability of this Agreement or any other Loan Document against the Borrower or the ability of the Borrower to perform its obligations under this Agreement or any other Loan Document.

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“Material Adverse Effect” means a material adverse effect (i) on the business, condition (financial or otherwise) or operations of the Borrower and its Subsidiaries, taken as a whole, or (ii) that is reasonably likely to affect the legality, validity or enforceability of this Agreement or any other Loan Document against the Borrower or the ability of the Borrower to perform its obligations under this Agreement or any other Loan Document.
“Maximum Rate” has the meaning specified in Section 8.18.
“Moody’s” means Moody’s Investors Service, Inc.
“Multiemployer Plan” has the meaning specified in Section 4.01(i).
“Non-Consenting Lender” means any Lender that does not approve any consent, waiver or amendment that (i) requires the approval of all Lenders in accordance with the terms of Section 8.01 and (ii) has been approved by the Required Lenders.
“Non-Defaulting Lender” means, at the time of determination, a Lender that is not a Defaulting Lender.
“Notice of Borrowing” has the meaning specified in Section 2.02(a).
“Notice of Conversion” means a written notice in substantially the form of Exhibit D hereto or any other form approved by the Administrative Agent containing the information required to be included therein by Section 2.09.
“Other Connection Taxes” means, with respect to any Recipient, Taxes imposed as a result of a present or former connection between such Recipient and the jurisdiction imposing such Tax (other than connections arising from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Loan Document, or sold or assigned an interest in any Advance, Commitment or Loan Document).
“Other Taxes” means all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, any Loan Document, except any such Taxes that are Other Connection Taxes imposed with respect to an assignment (other than an assignment made pursuant to Section 8.16).
“Participant” has the meaning specified in Section 8.07(d).
“Participant Register” has the meaning specified in Section 8.07(d).
“Patriot Act” has the meaning specified in Section 8.14.
“Permitted Liens” means such of the following as to which no enforcement, collection, execution, levy or foreclosure proceeding shall have been commenced: (i) Liens for taxes, assessments and governmental charges or levies to the extent not required to be paid under Section

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5.01(g) hereof; (ii) Liens imposed by law, such as materialmen’s, mechanics’, carriers’, workmen’s and repairmen’s Liens, and other similar Liens arising in the ordinary course of business securing obligations that are not overdue for a period of more than 30 days or that are being contested in good faith by appropriate proceedings; (iii) Liens incurred or deposits made to secure obligations under workers’ compensation laws or similar legislation or to secure public or statutory obligations; (iv) easements, rights of way and other encumbrances on title to real property that do not render title to the property encumbered thereby unmarketable or materially adversely affect the use of such property for its present purposes; (v) any judgment Lien, unless an Event of Default under Section 6.01(g) shall have occurred and be continuing; (vi) any Lien on any asset of any Person existing at the time such Person is merged or consolidated with or into the Borrower or any Significant Subsidiary thereof and not created in contemplation of such event; (vii) deposits made in the ordinary course of business to secure the performance of bids, trade contracts (other than for Debt), operating leases and surety bonds; (viii) Liens upon or in any real property or equipment acquired, constructed, improved or held the Borrower or any Subsidiary thereof in the ordinary course of business to secure the purchase price of such property or equipment or to secure Debt incurred solely for the purpose of financing the acquisition, construction or improvement of such property or equipment, or Liens existing on such property or equipment at the time of its acquisition (other than any such Liens created in contemplation of such acquisition that were not incurred to finance the acquisition of such property); (ix) extensions, renewals or replacements of any Lien described in clause (iii), (vi), (vii) or (viii) for the same or a lesser amount, provided, however, that no such Lien shall extend to or cover any properties not theretofore subject to the Lien being extended, renewed or replaced; and (x) any other Lien not covered by the foregoing exceptions as long as immediately after the creation of such Lien the aggregate principal amount of Debt secured by all Liens created or assumed under this clause (x) does not exceed 10% of Consolidated Tangible Net Assets of the Borrower.
“Person” means an individual, partnership, corporation (including a business trust), joint stock company, trust, unincorporated association, joint venture, limited liability company or other entity, or a government or any political subdivision or agency thereof.
“Plan” has the meaning specified in Section 4.01(i).
“Platform” has the meaning specified in Section 8.02(b).
“PTE” means a prohibited transaction class exemption issued by the U.S. Department of Labor, as any such exemption may be amended from time to time.
“Recipient” means the Administrative Agent or any Lender.
“Register” has the meaning specified in Section 8.07(c).
“Regulation AB” means rules promulgated by the SEC found at C.F.R. 229.1100 et seq.
“Related Parties” means, with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents, trustees, administrators, managers, advisors and representatives of such Person and of such Person’s Affiliates.

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“Required Lenders” means at any time Lenders having Advances and unused Commitments representing more than 50% of the sum of the then aggregate unpaid principal amount of the Advances owing to Lenders and unused Commitments in effect at such time, provided that if the Person serving as the Administrative Agent shall be a Lender at such time, then the term “Required Lenders” shall include such Person. Subject to Section 8.01, the unpaid principal amount of the Advances owing to any Defaulting Lender and the unused Commitments of any Defaulting Lender shall be disregarded in determining Required Lenders at any time.
“Resolution Authority” means an EEA Resolution Authority or, with respect to any UK Financial Institution, a UK Resolution Authority.
“Restructuring Law” means any law applicable to the Borrower or any Subsidiary of the Borrower governing the deregulation or restructuring of the electric power industry.
“RTO Transaction” means the transfer of transmission facilities to a regional transmission organization or equivalent organization as approved or ordered by the Federal Energy Regulatory Commission or the Oklahoma Corporation Commission.
“S&P” means Standard & Poor’s Ratings Group, a division of The McGraw-Hill Companies, Inc.
“Sanctioned Country” means, at any time of determination, a country, region or territory that is, or whose government is, the subject or target of any Sanctions, including a country subject to a sanctions program identified on the list maintained by OFAC and available at http://www.treasury.gov/resource-center/sanctions/Programs/Pages/Programs.aspx, or as otherwise published from time to time.
“Sanctioned Person” means, at any time of determination, any person with whom dealings are restricted or prohibited under Sanctions, including, without limitation, (a) any Person listed in any Sanctions-related list of designated Persons maintained by the Office of Foreign Assets Control of the U.S. Department of the Treasury, the U.S. Department of State, the United Nations Security Council, Her Majesty’s Treasury, the European Union, any EU member state or Her Majesty’s Treasury of the United Kingdom, (b) any Person operating, organized or resident in a Sanctioned Country, (c) any Person owned or controlled by or acting on behalf of any such Person described in the preceding clause (a) or (b), or (d) any Person with which, to the Borrower’s actual knowledge, any Lender is prohibited under Sanctions relevant to it from dealing or engaging in transactions. For purposes of the foregoing, control of a Person shall be deemed to include where a Sanctioned Person (i) owns or has power to vote 25% or more of the issued and outstanding equity interests having ordinary voting power for the election of directors of the Person or other individuals performing similar functions for the Person, or (ii) has the power to direct or cause the direction of the management and policies of the Person, whether by ownership of equity interests, contracts or otherwise.
“Sanctions” means all economic or financial sanctions, trade embargoes or restrictive measures enacted, imposed, administered or enforced from time to time by (a) the U.S. government, including those administered by the Office of Foreign Assets Control of the U.S. Department of the Treasury or by the U.S. Department of State, or (b) the United Nations Security

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Council, the European Union, any EU member state, Her Majesty’s Treasury of the United Kingdom or other relevant sanctions authority.
“SEC” means the United States Securities and Exchange Commission.
“Significant Subsidiary” means, at any time, any Subsidiary of the Borrower that constitutes at such time a “significant subsidiary” of the Borrower, as such term is defined in Regulation S-X of the SEC as in effect on the Closing Date (17 C.F.R. Part 210); provided, however, that “total assets” as used in Regulation S-X shall not include securitization transition assets, phase-in cost assets or similar assets on the balance sheet of any Subsidiary resulting from the issuance of transition bonds or other asset-backed securities of a similar nature.
“SMBC” has the meaning specified in the recital of parties to this Agreement.
“Stranded Cost Recovery Bonds” means securities, however denominated, that are issued by the Borrower or any Consolidated Subsidiary of the Borrower under Regulation AB that are (i) non-recourse to the Borrower and its Consolidated Subsidiaries (other than for failure to collect and pay over the charges referred to in clause (ii) below) and (ii) payable solely from transition or similar charges authorized by the Oklahoma Corporation Commission and to be invoiced to customers of the Borrower or any Subsidiary of the Borrower or to retail electric providers.
“Subsidiary” of any Person means any corporation, partnership, joint venture, limited liability company, trust or estate of which (or in which) more than 50% of (i) the issued and outstanding capital stock having ordinary voting power to elect a majority of the board of directors of such corporation (irrespective of whether at the time capital stock of any other class or classes of such corporation shall or might have voting power upon the occurrence of any contingency), (ii) the interest in the capital or profits of such limited liability company, partnership or joint venture or (iii) the beneficial interest in such trust or estate is at the time directly or indirectly owned or controlled by such Person, by such Person and one or more of its other Subsidiaries or by one or more of such Person’s other Subsidiaries.
“Taxes” means all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.
“Termination Date” means the earliest to occur of (i) July 19, 2022, (ii) the date of termination in whole of the Commitments available to the Borrower pursuant to Section 2.04; provided, that concurrently with such termination, the Borrower has repaid or prepaid all Advances outstanding under the Facility, including any accrued and unpaid interest thereon, and paid all other amounts owed under the Loan Documents, and (iii) the date of termination in whole of the Commitments available to the Borrower and/or the declaration of outstanding Advances, all interest thereon and all other amounts payable under this Agreement to be due and payable, in each case pursuant to Section 6.01.
“Type” refers to the distinction between Advances bearing interest at the Base Rate and Advances bearing interest at the Eurodollar Rate.

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“UK Financial Institution” means any BRRD Undertaking (as such term is defined under the PRA Rulebook (as amended from time to time) promulgated by the United Kingdom Prudential Regulation Authority) or any person falling within IFPRU 11.6 of the FCA Handbook (as amended from time to time) promulgated by the United Kingdom Financial Conduct Authority, which includes certain credit institutions and investment firms, and certain affiliates of such credit institutions or investment firms.
“UK Resolution Authority” means the Bank of England or any other public administrative authority having responsibility for the resolution of any UK Financial Institution.
“U.S. Person” means any Person that is a “United States Person” as defined in Section 7701(a)(30) of the Internal Revenue Code.
“U.S. Tax Compliance Certificate” has the meaning assigned to such term in Section 2.14(g).
“Voting Stock” means capital stock issued by a corporation, the membership interests in a limited liability company, or equivalent interests in any other Person, the holders of which are ordinarily, in the absence of contingencies, entitled to vote for the election of directors or managers (or Persons performing similar functions) of such Person, even if the right so to vote has been suspended by the happening of such a contingency.
“Withholding Agent” means the Borrower and the Administrative Agent.
“Write-Down and Conversion Powers” means, (a) with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule, and (b) with respect to the United Kingdom, any powers of the applicable Resolution Authority under the Bail-In Legislation to cancel, reduce, modify or change the form of a liability of any UK Financial Institution or any contract or instrument under which that liability arises, to convert all or part of that liability into shares, securities or obligations of that person or any other person, to provide that any such contract or instrument is to have effect as if a right had been exercised under it or to suspend any obligation in respect of that liability or any of the powers under that Bail-In Legislation that are related to or ancillary to any of those powers.
SECTION 1.02    Computation of Time Periods.
In this Agreement in the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including” and the words “to” and “until” each mean “to but excluding”.
SECTION 1.03    Accounting Terms.
All accounting terms not specifically defined herein shall be construed in accordance with generally accepted accounting principles applied in accordance with the consistency requirements thereof as in effect from time to time (“GAAP”); provided that (i) if the Borrower, by notice to the Administrative Agent, shall request an amendment to any provision hereof to eliminate the effect

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of any change occurring after the Closing Date in GAAP or in the application thereof on the operation of such provision (or if the Administrative Agent or the Required Lenders, by notice to the Borrower, shall request an amendment to any provision hereof for such purpose), regardless of whether any such notice is given before or after such change in GAAP or in the application thereof, then such provision shall be interpreted on the basis of GAAP as in effect and applied immediately before such change shall have become effective until such notice shall have been withdrawn or such provision amended in accordance herewith and (ii) notwithstanding any other provision contained herein, all terms of an accounting or financial nature used herein shall be construed, and all computations of amounts and ratios referred to herein shall be made, without giving effect to any change to GAAP occurring after December 31, 2018 as a result of the adoption of any proposals set forth in the Proposed Accounting Standards Update, Leases (Topic 840), issued by the Financial Accounting Standards Board on August 17, 2010, or any other proposals issued by the Financial Accounting Standards Board in connection therewith, in each case to the extent that such change would require treating any operating lease entered into on or prior to December 31, 2018 that would not otherwise constitute Debt as a capital lease where such operating lease would not constitute Debt and was not required to be so treated under GAAP as in effect on December 31, 2018.
SECTION 1.04    Other Interpretive Provisions.
As used herein, except as otherwise specified herein, (i) references to any Person include its successors and assigns and, in the case of any Governmental Authority, any Person succeeding to its functions and capacities; (ii) references to any Applicable Law include amendments, supplements and successors thereto; (iii) references to specific sections, articles, annexes, schedules and exhibits are to this Agreement; (iv) words importing any gender include the other gender; (v) the singular includes the plural and the plural includes the singular; (vi) the words “including”, “include” and “includes” shall be deemed to be followed by the words “without limitation”; (vii) captions and headings are for ease of reference only and shall not affect the construction hereof; and (viii) references to any time of day shall be to New York City time unless otherwise specified.
SECTION 1.05    Divisions.
For all purposes under the Loan Documents, in connection with any division or plan of division under Delaware law (or any comparable event under a different jurisdiction’s laws): (a) if any asset, right, obligation or liability of any Person becomes the asset, right, obligation or liability of a different Person, then it shall be deemed to have been transferred from the original Person to the subsequent Person, and (b) if any new Person comes into existence, such new Person shall be deemed to have been organized on the first date of its existence by the holders of its equity interests at such time.
ARTICLE II
AMOUNTS AND TERMS OF THE ADVANCES

SECTION 2.01    The Advances.

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At any time from and after the Closing Date to but excluding the Termination Date (such period, the “Commitment Period”), each Lender severally agrees, on the terms and conditions hereinafter set forth, to make Advances in Dollars to the Borrower on any Business Day during the Commitment Period in an aggregate outstanding amount not to exceed at any time such Lender’s Commitment at such time. Within the limits of each Lender’s Commitment and as hereinabove and hereinafter provided, the Borrower may request Borrowings hereunder, and repay or prepay Advances pursuant to Section 2.10. Amounts borrowed pursuant to this Section 2.01 may be repaid and reborrowed during the Commitment Period.
SECTION 2.02    Making the Advances.
(a)Each Borrowing shall be in an amount not less than $10,000,000 (or, if less, the Commitments at such time) or an integral multiple of $1,000,000 in excess thereof and shall consist of Eurodollar Rate Advances or Base Rate Advances, at the Borrower’s option, made on the same day by the Lenders ratably according to their respective Commitment Percentages; provided that, if a Eurodollar Rate Advance is unavailable under Section 2.08 or 2.12, such Borrowing shall consist of Base Rate Advances. Each Borrowing shall be made on notice, given not later than 1:00 P.M. (New York City time) on the third Business Day prior to the date of the proposed Borrowing in the case of a Borrowing consisting of Eurodollar Rate Advances, or not later than 12:00 noon (New York City time) on the date of the proposed Borrowing in the case of a Borrowing consisting of Base Rate Advances, by the Borrower to the Administrative Agent, which shall give to each Lender prompt written notice. Each such notice of a Borrowing under this Section 2.02 (a “Notice of Borrowing”) shall be by telephone, confirmed immediately in writing, or fax in substantially the form of Exhibit A hereto, specifying therein the requested (i) Borrowing Date for such Borrowing, (ii) Type of Advances comprising such Borrowing, (iii) aggregate amount of such Borrowing, and (iv) in the case of a Borrowing consisting of Eurodollar Rate Advances, the initial Interest Period for each such Advance. Each Lender shall, before 12:00 noon on the applicable Borrowing Date with respect to a Eurodollar Rate Advance and before 2:00 P.M. on the applicable Borrowing Date with respect to a Base Rate Advance, make available for the account of its Applicable Lending Office to the Administrative Agent at the Agent’s Account, in same day funds, such Lender’s ratable portion of the Borrowing to be made on such Borrowing Date. After the Administrative Agent’s receipt of such funds and upon fulfillment of the applicable conditions set forth in Section 3.02, the Administrative Agent will promptly make such funds available to the Borrower in such manner as the Borrower shall have specified in the applicable Notice of Borrowing and as shall be reasonably acceptable to the Administrative Agent.
(b)Anything in subsection (a) above to the contrary notwithstanding, (i) the Borrower may not select Eurodollar Rate Advances for any Borrowing if the aggregate amount of such Borrowing is less than $10,000,000 or if the obligation of the Lenders to make Eurodollar Rate Advances shall then be suspended pursuant to Section 2.08(b), 2.08(e) or 2.12, and (ii) there shall not be more than ten Borrowings consisting of Eurodollar Rate Advances outstanding at any time.
(c)Each Notice of Borrowing shall be irrevocable and binding on the Borrower. In the case of any Borrowing that the related Notice of Borrowing specifies is to comprise Eurodollar Rate Advances, the Borrower shall indemnify each Lender against any loss, cost or expense incurred by such Lender as a result of any failure to fulfill on or before the date

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specified in such Notice of Borrowing for such Borrowing the applicable conditions set forth in Section 3.02, including, without limitation, any loss (including loss of anticipated profits), cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by such Lender to fund the Advance to be made by such Lender as part of such Borrowing when such Advance, as a result of such failure, is not made on such date.
(d)Unless the Administrative Agent shall have received notice in writing from a Lender prior to any Borrowing Date or, in the case of a Base Rate Advance, prior to the time of Borrowing, that such Lender will not make available to the Administrative Agent such Lender’s Advance as part of the Borrowing to be made on such Borrowing Date, the Administrative Agent may, but shall not be required to, assume that such Lender has made such portion available to the Administrative Agent on such Borrowing Date in accordance with subsection (a) of this Section 2.02, and the Administrative Agent may (but it shall not be required to), in reliance upon such assumption, make available to the Borrower on such date a corresponding amount. If and to the extent that such Lender shall not have so made such Advance available to the Administrative Agent, such Lender and the Borrower severally agree to repay to the Administrative Agent forthwith on demand such corresponding amount, together with interest thereon, for each day from the date such amount is made available to the Borrower until the date such amount is repaid to the Administrative Agent, at (i) in the case of the Borrower, the interest rate applicable at the time to Advances comprising such Borrowing and (ii) in the case of such Lender, the Federal Funds Rate. If such Lender shall repay to the Administrative Agent such corresponding amount, such amount so repaid shall constitute such Lender’s Advance as part of such Borrowing for purposes of this Agreement.
(e)The failure of any Lender to make the Advance to be made by it as part of any Borrowing shall not relieve any other Lender of its obligation, if any, hereunder to make its Advance on the date of such Borrowing, but no Lender shall be responsible for the failure of any other Lender to make the Advance to be made by such other Lender on the date of any Borrowing.
SECTION 2.03    Fees.
(a)The Borrower agrees to pay to the Administrative Agent for the account of each Lender a commitment fee equal to the product of (x) the Commitment Fee Rate in effect from time to time multiplied by (y) the amount of such Lender’s daily unused Commitment, in each case from (i) the Closing Date, in the case of each Initial Lender, and (ii) from the effective date specified in the Assignment and Assumption pursuant to which it became a Lender, in the case of each other Lender, payable quarterly in arrears on the last day of each March, June, September and December and on the Termination Date, commencing March 31, 2021, and ending on the Termination Date.
(b)The Borrower shall pay to the Administrative Agent such fees as may from time to time be agreed between the Borrower and the Administrative Agent, including pursuant to the Fee Letter.
SECTION 2.04    Termination or Reduction of the Commitments.

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(a)The Borrower shall have the right, upon at least three Business Days’ notice to the Administrative Agent, to terminate in whole or reduce ratably in part the Commitments in an amount up to the amount by which the Commitments exceed the aggregate principal amount of all outstanding Advances at the time of such proposed termination or reduction; provided that each partial reduction shall be in a minimum amount of $1,000,000 or an integral multiple of $1,000,000 in excess thereof.
(b)The Commitment of each Lender shall automatically terminate, if not previously terminated under the terms hereof, on the Termination Date.
(c)Once terminated, neither a Commitment nor any portion thereof may be reinstated.
SECTION 2.05    Repayment of Advances.
The Borrower shall repay to the Administrative Agent for the account of each Lender on the Termination Date the aggregate principal amount of all Advances made by such Lender to the Borrower then outstanding.
SECTION 2.06     Evidence of Indebtedness.
(a)Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness to such Lender resulting from each Advance made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time under this Agreement.
(b)The Administrative Agent shall maintain accounts in which it will record (i) the amount of each Advance made hereunder, the Type of each Advance made and the Interest Period applicable thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder and (iii) the amount of any sum received by the Administrative Agent hereunder from the Borrower and each Lender’s share thereof.
(c)The entries made in the accounts maintained pursuant to subsections (a) and (b) of this Section 2.06 shall, to the extent permitted by Applicable Law, be prima facie evidence of the existence and amounts of the obligations therein recorded; provided, however, that the failure of any Lender or the Administrative Agent to maintain such accounts or any error therein shall not in any manner affect the obligations of the Borrower to repay the Advances and interest thereon in accordance with the terms of this Agreement.
(d)Any Lender may request that any Advances made by it be evidenced by one or more promissory notes. In such event, the Borrower shall prepare, execute and deliver to such Lender one or more promissory notes payable to such Lender (or, if requested by such Lender, to such Lender and its registered assigns) and in a form approved by the Administrative Agent. Thereafter, the Advances evidenced by such promissory notes and interest thereon shall at all times (including after assignment pursuant to Section 8.07) be represented by one or more promissory notes in such form payable to the payee named therein (or, if such promissory note is a registered note, to such payee and its registered assigns).

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SECTION 2.07    Interest on Advances.
The Borrower shall pay interest on the unpaid principal amount of each Advance from the date of such Advance until such principal amount shall be paid in full, at the following rates per annum:
(a)Base Rate Advances. During such periods as such Advance is a Base Rate Advance, a rate per annum equal at all times to the sum of (x) the Base Rate plus (y) the Applicable Margin for Base Rate Advances in effect from time to time, payable in arrears (i) quarterly on the last day of each March, June, September and December during such periods, (ii) on the date such Base Rate Advance shall be Converted or paid in full and (iii) on the Termination Date.
(b)Eurodollar Rate Advances. During such periods as such Advance is a Eurodollar Rate Advance, a rate per annum equal at all times during each Interest Period for such Advance to the sum of (x) the Eurodollar Rate for such Interest Period for such Advance plus (y) the Applicable Margin for Eurodollar Rate Advances in effect from time to time, payable in arrears (i) on the last day of such Interest Period and, if such Interest Period has a duration of more than three months, on each day that occurs during such Interest Period every three months from the first day of such Interest Period, (ii) on the date such Eurodollar Rate Advance shall be Converted or paid in full and (iii) on the Termination Date.
(c)Additional Interest on Eurodollar Rate Advances. The Borrower shall pay to each Lender, so long as such Lender shall be required under regulations of the Board of Governors of the Federal Reserve System to maintain reserves with respect to liabilities or assets consisting of or including Eurocurrency Liabilities, additional interest on the unpaid principal amount of each Eurodollar Rate Advance of such Lender, from the date of such Advance until such principal amount is paid in full, at an interest rate per annum equal at all times to the remainder obtained by subtracting (i) the Eurodollar Rate for the Interest Period for such Advance from (ii) the rate obtained by dividing such Eurodollar Rate by a percentage equal to 100% minus the Eurodollar Rate Reserve Percentage of such Lender for such Interest Period, payable on each date on which interest is payable on such Advance. Such additional interest shall be determined by such Lender and notified to the Borrower through the Administrative Agent.
SECTION 2.08    Interest Rate Determination.
(a)The Administrative Agent shall give prompt notice to the Borrower and the Lenders of the applicable interest rate determined by the Administrative Agent for purposes of Section 2.07(a) or (b).
(b)If, with respect to any Eurodollar Rate Advances, (i) the Required Lenders notify the Administrative Agent that the Eurodollar Rate for any Interest Period for such Advances will not adequately reflect the cost to such Required Lenders of making, funding or maintaining their respective Eurodollar Rate Advances for such Interest Period, or (ii) a Eurodollar Rate cannot be determined or is otherwise unavailable, the Administrative Agent shall forthwith so notify the Borrower and the Lenders, whereupon (A) each Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period therefor, Convert into a Base Rate Advance, and (B) the obligation of the Lenders to make, or to Convert Advances into, Eurodollar Rate Advances

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shall be suspended until the Administrative Agent shall notify the Borrower and the Lenders that the circumstances causing such suspension no longer exist.
(c)If the Borrower shall fail to select the duration of any Interest Period for any Eurodollar Rate Advances in accordance with the provisions contained in the definition of “Interest Period” in Section 1.01, the Administrative Agent will forthwith so notify the Borrower and the Lenders and such Advances will automatically, on the last day of the then existing Interest Period therefor, Convert into Base Rate Advances.
(d)On the date on which the aggregate unpaid principal amount of Eurodollar Rate Advances comprising any Borrowing shall be reduced, by payment or prepayment or otherwise, to less than $10,000,000, such Advances shall automatically Convert into Base Rate Advances.
(e)Upon the occurrence and during the continuance of any Event of Default, (i) each Eurodollar Rate Advance comprising the same Borrowing will automatically, on the last day of the then existing Interest Period therefor, Convert into a Base Rate Advance and (ii) the obligation of the Lenders to make, or to Convert Advances into, Eurodollar Rate Advances shall be suspended.
SECTION 2.09    Optional Conversion of Advances.
The Borrower may on any Business Day, upon delivery of a Notice of Conversion to the Administrative Agent not later than 1:00 P.M. (New York City time) on the third Business Day prior to the date of the proposed Conversion and subject to the provisions of Sections 2.08 and 2.12, Convert all or any part of Advances of one Type comprising the same Borrowing into Advances of the other Type or of the same Type but having a new Interest Period; provided, however, that any Conversion of Eurodollar Rate Advances into Base Rate Advances shall be made only on the last day of an Interest Period for such Eurodollar Rate Advances, any Conversion of Base Rate Advances into Eurodollar Rate Advances shall be in an amount not less than the minimum amount specified in Section 2.02(b), and no Conversion of any Advances shall result in more separate Borrowings consisting of Eurodollar Rate Advances than permitted under Section 2.02(b). Each such Notice of Conversion shall, within the restrictions specified above, specify (i) the date of such Conversion, (ii) the Advances to be Converted, and (iii) if such Conversion is into Eurodollar Rate Advances, the duration of the initial Interest Period for each such Advance. Each notice of Conversion shall be irrevocable and binding on the Borrower.
SECTION 2.10    Optional Prepayments of Advances.
The Borrower may, upon at least three Business Days’ notice, in the case of Eurodollar Rate Advances, and upon notice not later than 11:00 A.M. (New York City time) on the date of prepayment, in the case of Base Rate Advances, to the Administrative Agent stating the proposed date and aggregate principal amount of the prepayment, and, if such notice is given, the Borrower shall prepay the outstanding principal amount of the Advances comprising part of the same Borrowing in whole or ratably in part, together with accrued interest to the date of such prepayment on the principal amount prepaid; provided, however, that (x) each partial prepayment shall be in a minimum amount of $5,000,000 or an integral multiple of $1,000,000 in excess thereof and (y) in

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the event of any such prepayment of a Eurodollar Rate Advance, the Borrower shall be obligated to reimburse the Lenders in respect thereof pursuant to Section 8.04(d).
SECTION 2.11    Increased Costs.
(a)Increased Costs Generally. If any Change in Law shall:
(i)impose, modify or deem applicable any reserve, special deposit, compulsory loan, insurance charge or similar requirement against assets of, deposits with or for the account of, or credit extended or participated in by, any Lender (except any reserve requirement reflected in the Eurodollar Rate Reserve Percentage);
(ii)subject any Recipient to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clauses (ii) through (iv) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its loans, loan principal, letters of credit, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto; or

(iii)impose on any Lender or the London interbank market any other condition, cost or expense (other than Taxes) affecting this Agreement or Advances made by such Lender or participation therein;

and the result of any of the foregoing shall be to increase the cost to such Lender or such other Recipient of making, converting to, continuing or maintaining any Advance or of maintaining its obligation to make any such Advance, or to reduce the amount of any sum received or receivable by such Lender or other Recipient hereunder (whether of principal, interest or any other amount) then, upon request of such Lender or other Recipient, the Borrower will pay to such Lender or other Recipient, as the case may be, such additional amount or amounts as will compensate such Lender or other Recipient, as the case may be, for such additional costs incurred or reduction suffered.
(b)Capital Requirements. If any Lender determines that any Change in Law affecting such Lender or any Applicable Lending Office of such Lender or such Lender’s holding company, if any, regarding capital or liquidity requirements, has or would have the effect of reducing the rate of return on such Lender’s capital or on the capital of such Lender’s holding company, if any, as a consequence of this Agreement, the Commitments of such Lender or the Advances made by such Lender, to a level below that which such Lender or such Lender’s or holding company could have achieved but for such Change in Law (taking into consideration such Lender’s policies and the policies of such Lender’s holding company with respect to capital adequacy or liquidity), then from time to time the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender or such Lender’s holding company for any such reduction suffered.
(c)Certificates for Reimbursement. A certificate of a Lender setting forth the amount or amounts necessary to compensate such Lender or its holding company, as the case may be, as specified in subsection (a) or (b) of this Section and delivered to the Borrower, shall be conclusive absent manifest error. The Borrower shall pay such Lender, as the case may be, the amount shown as due on any such certificate within 10 days after receipt thereof.

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(d)Delay in Requests. Failure or delay on the part of any Lender to demand compensation pursuant to this Section shall not constitute a waiver of such Lender’s right to demand such compensation; provided that the Borrower shall not be required to compensate a Lender pursuant to this Section for any increased costs incurred or reductions suffered more than 180 days prior to the date that such Lender notifies the Borrower of the Change in Law giving rise to such increased costs or reductions, and of such Lender’s intention to claim compensation therefor (except that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the 180 day period referred to above shall be extended to include the period of retroactive effect thereof).
SECTION 2.12    Illegality.
If due to any Change in Law it shall become unlawful or impossible for any Recipient (or its Eurodollar Lending Office) to make, maintain or fund its Eurodollar Rate Advances, and such Recipient shall so notify the Administrative Agent, the Administrative Agent shall forthwith give notice thereof to the other Recipients and the Borrower, whereupon, until such Recipient notifies the Borrower and the Administrative Agent that the circumstances giving rise to such suspension no longer exist, the obligation of such Recipient to make Eurodollar Rate Advances, or to Convert outstanding Advances into Eurodollar Rate Advances, shall be suspended. Before giving any notice to the Administrative Agent pursuant to this Section 2.12, such Recipient shall use reasonable efforts (consistent with its internal policy and legal and regulatory restrictions applicable to such Recipient) to designate a different Eurodollar Lending Office if such designation would avoid the need for giving such notice and would not, in the judgment of such Recipient, be otherwise disadvantageous to such Recipient. If such notice is given, each Eurodollar Rate Advance of such Recipient then outstanding shall be Converted to a Base Rate Advance either (i) on the last day of the then current Interest Period applicable to such Eurodollar Rate Advance if such Recipient may lawfully continue to maintain and fund such Advance to such day or (ii) immediately if such Recipient shall determine that it may not lawfully continue to maintain and fund such Advance to such day.
SECTION 2.13    Payments and Computations.
(a)The Borrower shall make each payment to be made by it hereunder not later than 1:00 P.M. on the day when due in Dollars to the Administrative Agent at the Agent’s Account in same day funds without condition or deduction for any counterclaim, defense, recoupment or setoff. The Administrative Agent will promptly thereafter cause to be distributed like funds relating to the payment of principal or interest or commitment fees ratably (other than amounts payable pursuant to Section 2.02(c), 2.11, 2.14, 8.04(d) and 8.16) to the Lenders for the account of their respective Applicable Lending Offices, and like funds relating to the payment of any other amount payable to any Lender to such Lender for the account of its Applicable Lending Office, in each case to be applied in accordance with the terms of this Agreement. Upon its acceptance of an Assignment and Assumption and recording of the information contained therein in the Register pursuant to Section 8.07(c), from and after the effective date specified in such Assignment and Assumption, the Administrative Agent shall make all payments hereunder in respect of the interest assigned thereby to the Lender assignee thereunder, and the parties to such Assignment and Assumption shall make all appropriate adjustments in such payments for periods prior to such effective date directly between themselves.

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(b)The Borrower hereby authorizes each Lender, if and to the extent payment owed to such Lender is not made when due hereunder, after any applicable grace period, to charge from time to time against any or all of the Borrower’s accounts with such Lender any amount so due.
(c)All computations of interest based on the rate referred to in clause (i) of the definition of the “Base Rate” contained in Section 1.01 shall be made by the Administrative Agent on the basis of a year of 365 or 366 days, as the case may be, and all computations of interest based on the Eurodollar Rate or the Federal Funds Rate and of commitment fees shall be made by the Administrative Agent on the basis of a year of 360 days, in each case for the actual number of days (including the first day but excluding the last day) occurring in the period for which such interest or commitment fees are payable. Each determination by the Administrative Agent of an interest rate or commitment fees hereunder shall be conclusive and binding for all purposes, absent manifest error.
(d)Whenever any payment hereunder shall be stated to be due on a day other than a Business Day, such payment shall be made on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of payment of interest or commitment fees, as the case may be; provided, however, that, if such extension would cause payment of interest on or principal of Eurodollar Rate Advances to be made in the next following calendar month or on a date after the Termination Date, such payment shall be made on the next preceding Business Day.
(e)Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to a Lender hereunder that the Borrower will not make such payment in full, the Administrative Agent may assume that the Borrower has made such payment in full to the Administrative Agent on such date, and the Administrative Agent may, in reliance upon such assumption, cause to be distributed to each Lender on such due date an amount equal to the amount then due such Lender. If and to the extent that the Borrower shall not have so made such payment in full to the Administrative Agent, each Lender shall repay to the Administrative Agent forthwith on demand such amount distributed to such Lender together with interest thereon, for each day from the date such amount is distributed to such Lender until the date such Lender repays such amount to the Administrative Agent, at the Federal Funds Rate.
SECTION 2.14    Taxes.
(a)Defined Terms. For purposes of this Section 2.14, the term “Applicable Law” includes FATCA.
(b)Payments Free of Taxes. Any and all payments by or on account of any obligation of the Borrower under any Loan Document shall be made without deduction or withholding for any Taxes, except as required by Applicable Law. If any Applicable Law (as determined in the good faith discretion of an applicable Withholding Agent) requires the deduction or withholding of any Tax from any such payment by a Withholding Agent, then the applicable Withholding Agent shall be entitled to make such deduction or withholding and shall timely pay the full amount deducted or withheld to the relevant Governmental Authority in accordance with Applicable Law and, if such Tax is an Indemnified Tax, then the sum payable by the Borrower

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shall be increased as necessary so that after such deduction or withholding has been made (including such deductions and withholdings applicable to additional sums payable under this Section 2.14) the applicable Recipient receives an amount equal to the sum it would have received had no such deduction or withholding been made.
(c)Payment of Other Taxes by the Borrower. The Borrower shall timely pay to the relevant Governmental Authority in accordance with Applicable Law, or at the option of the Administrative Agent timely reimburse it for the payment of, any Other Taxes.
(d)Indemnification by the Borrower. The Borrower shall indemnify each Recipient, within 10 days after demand therefor, for and hold it harmless against the full amount of any Indemnified Taxes (including, without limitation, Indemnified Taxes imposed or asserted on or attributable to amounts payable under this Section 2.14), payable or paid by such Recipient or required to be withheld or deducted from a payment to such Recipient and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to the Borrower by a Lender (with a copy to the Administrative Agent), or by the Administrative Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.
(e)Indemnification by the Lenders. Each Lender shall severally indemnify the Administrative Agent, within 10 days after demand therefor, for (i) any Indemnified Taxes attributable to such Lender (but only to the extent that the Borrower has not already indemnified the Administrative Agent for such Indemnified Taxes and without limiting the obligation of the Borrower to do so), (ii) any Taxes attributable to such Lender’s failure to comply with the provisions of Section 8.07(d) relating to the maintenance of a Participant Register and (iii) any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Administrative Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to any Lender by the Administrative Agent shall be conclusive absent manifest error. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender under any Loan Document or otherwise payable by the Administrative Agent to the Lender from any other source against any amount due to the Administrative Agent under this subsection (e).
(f)Evidence of Payments. As soon as practicable after any payment of Taxes by the Borrower to a Governmental Authority pursuant to this Section 2.14, the Borrower shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.
(g)Status of Lenders.     Any Lender that is entitled to an exemption from or reduction of withholding Tax with respect to payments made under any Loan Document shall deliver to the Borrower and the Administrative Agent, at the time or times reasonably requested by the Borrower or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Borrower or the Administrative Agent as will permit

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such payments to be made without withholding or at a reduced rate of withholding. In addition, any Lender, if reasonably requested by the Borrower or the Administrative Agent, shall deliver such other documentation prescribed by Applicable Law or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements. Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in Section 2.14(g)(ii)(A), (ii)(B) and (ii)(D) below) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.
(ii)Without limiting the generality of the foregoing,
(A)any Lender that is a U.S. Person shall deliver to the Borrower and the Administrative Agent on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed copies of IRS Form W-9 certifying that such Lender is exempt from U.S. federal backup withholding tax;
(B)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), whichever of the following is applicable:
(1)in the case of a Foreign Lender claiming the benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Loan Document, executed copies of IRS Form W-8BEN or IRS Form W-8BEN-E establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “interest” article of such tax treaty and (y) with respect to any other applicable payments under any Loan Document, IRS Form W-8BEN or IRS Form W-8BEN-E establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;
(2)executed copies of IRS Form W-8ECI;

(3)in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Internal Revenue Code, (x) a certificate substantially in the form of Exhibit C-1 to the effect that such Foreign Lender is not a “bank” within the meaning of Section 881(c)(3)(A) of the Internal Revenue Code, a “10 percent shareholder” of the Borrower within the meaning of Section 881(c)(3)(B)

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of the Internal Revenue Code, or a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Internal Revenue Code (a “U.S. Tax Compliance Certificate”) and (y) executed copies of IRS Form W-8BEN or IRS Form W-8BEN-E; or

(4)to the extent a Foreign Lender is not the beneficial owner, executed copies of IRS Form W-8IMY, accompanied by IRS Form W-8ECI, IRS Form W-8BEN, IRS Form W-8BEN-E, a U.S. Tax Compliance Certificate substantially in the form of Exhibit C-2 or Exhibit C-3, IRS Form W-9, and/or other certification documents from each beneficial owner, as applicable; provided that if the Foreign Lender is a partnership and one or more direct or indirect partners of such Foreign Lender are claiming the portfolio interest exemption, such Foreign Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit C-4 on behalf of each such direct and indirect partner;

(C)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed copies of any other form prescribed by Applicable Law as a basis for claiming exemption from or a reduction in U.S. federal withholding Tax, duly completed, together with such supplementary documentation as may be prescribed by Applicable Law to permit the Borrower or the Administrative Agent to determine the withholding or deduction required to be made; and
(D)if a payment made to a Lender under any Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Internal Revenue Code, as applicable), such Lender shall deliver to the Borrower and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent such documentation prescribed by Applicable Law (including as prescribed by Section 1471(b)(3)(C)(i) of the Internal Revenue Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this clause (D), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.
(E)Each Lender agrees that if any form or certification it previously delivered expires or becomes obsolete or inaccurate in any respect, it shall update such form or certification or promptly notify the Borrower and the Administrative Agent in writing of its legal inability to do so.

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(h)Treatment of Certain Refunds. If any party determines, in its sole discretion exercised in good faith, that it has received a refund of any Taxes as to which it has been indemnified pursuant to this Section 2.14 (including by the payment of additional amounts pursuant to this Section 2.14), it shall pay to the indemnifying party an amount equal to such refund (but only to the extent of indemnity payments made under this Section 2.14 with respect to the Taxes giving rise to such refund), net of all out-of-pocket expenses (including Taxes) of such indemnified party and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund). Such indemnifying party, upon the request of such indemnified party, shall repay to such indemnified party the amount paid over pursuant to this subsection (h) (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) in the event that such indemnified party is required to repay such refund to such Governmental Authority. Notwithstanding anything to the contrary in this subsection (h), in no event will the indemnified party be required to pay any amount to an indemnifying party pursuant to this subsection (h) the payment of which would place the indemnified party in a less favorable net after-Tax position than the indemnified party would have been in if the Tax subject to indemnification and giving rise to such refund had not been deducted, withheld or otherwise imposed and the indemnification payments or additional amounts with respect to such Tax had never been paid. This subsection shall not be construed to require any indemnified party to make available its Tax returns (or any other information relating to its Taxes that it deems confidential) to the indemnifying party or any other Person.
(i)FATCA Withholding. For purposes of determining withholding Taxes imposed under FATCA, from and after the Closing Date, the Borrower and the Administrative Agent shall treat (and the Lenders hereby authorize the Administrative Agent to treat) the obligations of the Borrower set forth in this Agreement as not qualifying as a “grandfathered obligation” within the meaning of Treasury Regulation Sections 1.1471-2(b)(2)(i) and 1.1471-2T(b)(2)(i).
(j)Survival. Each party’s obligations under this Section 2.14 shall survive the resignation or replacement of the Administrative Agent or any assignment of rights by, or the replacement of, a Lender, the termination of the Commitments and the repayment, satisfaction or discharge of all obligations under any Loan Document.
SECTION 2.15    Mitigation Obligations; Replacement of Lenders.
(a)Designation of a Different Applicable Lending Office. If any Lender delivers a notice pursuant to Section 2.12, requests compensation under Section 2.11, or the Borrower is required to pay any Indemnified Taxes or additional amounts to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.14, then such Lender shall (at the request of the Borrower) use reasonable efforts to designate a different Applicable Lending Office for funding or booking its Advances hereunder or to assign its rights and obligations hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 2.11 or 2.14, as the case may be, in the future, and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. The Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender in connection with any such designation or assignment.

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(b)Replacement of Lenders. If any Lender delivers a notice pursuant to Section 2.12, requests compensation under Section 2.11, or requires the Borrower to pay any Indemnified Taxes or additional amounts to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.14 and, in each case, such Lender has declined or is unable to designate a different Applicable Lending Office in accordance with subsection (a) above, or if any Lender is a Defaulting Lender or a Non-Consenting Lender, then the Borrower may, at its sole expense and effort, upon notice to such Lender and the Administrative Agent, require such Lender to assign and delegate, without recourse (in accordance with and subject to the restrictions contained in, and consents required by, Section 8.07), all of its interests, rights (other than its existing rights to payments pursuant to Section 2.11 or Section 2.14) and obligations under this Agreement and the related Loan Documents to an Eligible Assignee that shall assume such obligations (which assignee may be another Lender, if such Lender accepts such assignment); provided that:
(i)the Borrower shall have paid to the Administrative Agent the assignment fee (if any) specified in Section 8.07(b)(iv);
(ii)such Lender shall have received payment of an amount equal to the outstanding principal amounts of its Advances, accrued interest thereon, accrued fees and all other amounts payable to it hereunder and under the other Loan Documents (including any amounts under Section 8.04(d)) from the assignee (to the extent of such outstanding principal and accrued interest and fees) or the Borrower (in the case of all other amounts);

(iii)in the case of any such assignment resulting from a claim for compensation under Section 2.11 or payments required to be made pursuant to Section 2.14, such assignment will result in a reduction in such compensation or payments thereafter;
(iv)no Default shall have occurred and be continuing;

(v)such assignment does not conflict with Applicable Law; and

(vi)in the case of any assignment resulting from a Lender becoming a Non-Consenting Lender, the applicable assignee shall have consented to the applicable amendment, waiver or consent.

A Lender shall not be required to make any such assignment or delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Borrower to require such assignment and delegation cease to apply.
SECTION 2.16    Sharing of Payments, Etc.
(a)If any Lender shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off, or otherwise) on account of the Advances owing to it (other than pursuant to Section 2.02(c), 2.11, 2.14, 8.04(d) or 8.16 or in respect of Eurodollar Rate Advances converted into Base Rate Advances pursuant to Section 2.12) by the Borrower, in excess of its ratable share of payments on account of the Advances to the Borrower, obtained by all the Lenders, such Lender shall forthwith purchase from the other Lenders such participations in such

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Advances owing to them as shall be necessary to cause such purchasing Lender to share the excess payment ratably with each of them; provided, however, that if all or any portion of such excess payment is thereafter recovered from such purchasing Lender, such purchase from each Lender shall be rescinded and such Lender shall repay to the purchasing Lender the purchase price to the extent of such recovery together with an amount equal to such Lender’s ratable share (according to the proportion of (i) the amount of such Lender’s required repayment to (ii) the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. The Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section 2.16 may, to the fullest extent permitted by law, exercise all its rights of payment (including the right of set-off) with respect to such participation as fully as if such Lender were the direct creditor of the Borrower in the amount of such participation.
(b)If any Lender shall fail to make any payment required to be made by it hereunder to or for the account of the Administrative Agent, then the Administrative Agent may, in its discretion and notwithstanding any contrary provision hereof, (i) apply any amounts thereafter received by the Administrative Agent for the account of such Lender for the benefit of the Administrative Agent to satisfy such Lender’s obligations in respect of such payment until all such unsatisfied obligations are fully paid, and/or (ii) hold any such amounts in a segregated account as cash collateral for, and application to, any future funding obligations of such Lender under any such Section, in the case of each of clauses (i) and (ii) above, in any order as determined by the Administrative Agent in its discretion.
ARTICLE III
CONDITIONS PRECEDENT

SECTION 3.01    Conditions Precedent to the Closing Date and Initial Advances.

The effectiveness of this Agreement and the obligation of each Lender to make the initial Advance to be made by it hereunder shall be subject to the satisfaction of the following conditions precedent:
(a)The Administrative Agent shall have received on or before the date of such effectiveness the following, each dated such day, in form and substance reasonably satisfactory to the Administrative Agent in sufficient copies for each Lender:
(i)Certified copies of the Borrower’s certificate of incorporation and bylaws and the resolutions of the board of directors of the Borrower approving this Agreement, a certificate of good standing for the Borrower from its jurisdiction of incorporation and of all documents evidencing other necessary corporate action and Governmental Approvals, if any, with respect to this Agreement;
(ii)A certificate of the Secretary or Assistant Secretary of the Borrower certifying the names and true signatures of the officers of the Borrower authorized to sign this Agreement and the other documents to be delivered by the Borrower hereunder; and
(iii)A favorable opinion of counsel for the Borrower (which may be an attorney of American Electric Power Service Corporation), as to such matters as any Lender through the Administrative Agent may reasonably request.

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(b)On such date, the following statements shall be true and the Administrative Agent shall have received a certificate signed by a duly authorized officer of the Borrower, dated such date, certifying to the Administrative Agent and each Lender that:

(i)The representations and warranties of the Borrower contained in Section 4.01 are true and correct in all material respects on and as of such date, as though made on and as of such date, and
(ii)No event has occurred and is continuing that constitutes a Default.

(c)The Borrower shall have paid all accrued fees and expenses of the Administrative Agent, the Arrangers and the Lenders then due and payable in accordance with the terms of the Loan Documents (including all fees as provided in the Fee Letter and all the fees and expenses of counsel to the Administrative Agent to the extent then due and payable).
(d)The Administrative Agent, on behalf of each Lender, shall have received copies of all the Disclosure Documents.
(e)The Administrative Agent shall have received counterparts of this Agreement, executed and delivered by the Borrower and the Lenders.
(f)The Administrative Agent shall have received all promissory notes (if any) requested by any Lender pursuant to Section 2.06(d), duly completed and executed by the Borrower and payable to any such Lender.
(g)The Administrative Agent shall have received (i) all documentation and information required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including, without limitation, the Patriot Act, to the extent such documentation or information is requested by the Administrative Agent on behalf of the Lenders prior to the Closing Date and (ii) at least five days prior to the Closing Date, if the Borrower qualifies as a “legal entity customer” under the Beneficial Ownership Regulation, a Beneficial Ownership Certification in relation to the Borrower.
(h)The Administrative Agent shall have received copies or other evidence of such orders, filings, and other Governmental Approvals of any Governmental Authority that may be applicable to the transactions contemplated by this Agreement including those described in Section 4.01(d), and such other approvals, opinions or documents as may reasonably be requested by the Administrative Agent or by any Lender through the Administrative Agent
(i)The Administrative Agent shall have received the Notice of Borrowing for any Advance to be made on the Closing Date.
SECTION 3.02    Conditions Precedent to each Advance.

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The obligation of each Lender to make each Advance to be made by it hereunder (other than in connection with any Borrowing that would not increase the aggregate principal amount of Advances outstanding immediately prior to the making of such Borrowing) shall be subject to the satisfaction of the conditions precedent set forth in Section 3.01 and on the date of such Borrowing:
(a)The following statements shall be true (and each of the giving of the applicable Notice of Borrowing and the acceptance by the Borrower of the proceeds of any Borrowing shall constitute a representation and warranty by the Borrower that on the date of such Borrowing such statements are true):
(i)The representations and warranties of the Borrower contained in Section 4.01 (other than, with respect to Advances to be made after the Closing Date, (A) the representation and warranty in Section 4.01(e) and (B) the representation and warranty set forth in the penultimate sentence of Section 4.01(f)) are true and correct in all material respects (or, if already qualified by materiality, in all respects) on and as of the date of such Borrowing, before and after giving effect to such Borrowing and to the application of the proceeds therefrom, as though made on and as of such date, and
(ii)No event has occurred and is continuing or would result from such Borrowing or from the application of the proceeds therefrom, that constitutes a Default.

(b)The Administrative Agent shall have received copies or other evidence of such other approvals and such other opinions or documents as may be reasonably requested by the Administrative Agent or by any Lender through the Administrative Agent.
ARTICLE IV
REPRESENTATIONS AND WARRANTIES

SECTION 4.01    Representations and Warranties of the Borrower.
The Borrower represents and warrants as follows:
(a)The Borrower is a corporation duly organized, validly existing and in good standing under the laws of the jurisdiction in which it is incorporated, and each Significant Subsidiary is duly organized, validly existing and in good standing under the laws of the jurisdiction in which it is incorporated or otherwise organized.
(b)The execution, delivery and performance by the Borrower of each Loan Document, and the consummation of the transactions contemplated hereby, are within the Borrower’s corporate powers, have been duly authorized by all necessary action, and do not contravene (i) the Borrower’s certificate of incorporation or by-laws, (ii) law binding or affecting the Borrower or (iii) any contractual restriction binding on or affecting the Borrower or any of its properties.
(c)Each Loan Document has been duly executed and delivered by the Borrower. Each Loan Document is the legal, valid and binding obligation of the Borrower enforceable against the Borrower in accordance with its terms, except as the enforceability thereof may be limited by bankruptcy, insolvency, fraudulent conveyance or other similar laws affecting

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the enforcement of creditors’ rights in general, and except as the availability of the remedy of specific performance is subject to general principles of equity (regardless of whether such remedy is sought in a proceeding in equity or at law) and subject to requirements of reasonableness, good faith and fair dealing.
(d)No Governmental Approval or other action by, and no notice to or filing with, any Governmental Authority or other third party, or otherwise specified pursuant to any Applicable Law, is required for the due execution, delivery and performance by the Borrower of any Loan Document, except for the authorization of the Oklahoma Corporation Commission, which authorization has been duly obtained and is in full force and effect as of the date hereof.
(e)There is no pending or threatened action, suit, investigation, litigation or proceeding, including, without limitation, any Environmental Action, affecting the Borrower or any of its Significant Subsidiaries before any Governmental Authority or arbitrator that is reasonably likely to have a Material Adverse Effect, except as may be disclosed in the Disclosure Documents.
(f)The consolidated balance sheets of the Borrower and its Consolidated Subsidiaries as at December 31, 2019, March 31, 2020, June 30, 2020 and September 30, 2020, and the related consolidated statements of income and cash flows of the Borrower and its Consolidated Subsidiaries for the fiscal periods then ended, accompanied by (in the case of such financial statements for the fiscal year ended December 31, 2019) an opinion of PricewaterhouseCoopers LLP, an independent registered public accounting firm, copies of each of which have been furnished to each Lender, fairly present (subject, in the case of such financial statements for the fiscal quarters ended March 31, 2020, June 30, 2020 and September 30, 2020 to year-end adjustments) the consolidated financial condition of the Borrower and its Consolidated Subsidiaries as at such dates and the consolidated results of the operations of the Borrower and its Consolidated Subsidiaries for the periods ended on such dates, all in accordance with GAAP consistently applied. Since December 31, 2019, there has been no Material Adverse Change. As of the Closing Date, the information included in the Beneficial Ownership Certification is true and correct in all respects.
(g)No written statement, information, report, financial statement, exhibit or schedule furnished by or on behalf of the Borrower to the Administrative Agent or any Lender in connection with the syndication or negotiation of this Agreement or included herein or delivered pursuant hereto contained, contains, or will contain any material misstatement of fact or intentionally omitted, omits, or will omit to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were, are, or will be made, not misleading.
(h)Except as may be disclosed in the Disclosure Documents, the Borrower and each Significant Subsidiary is in material compliance with all laws (including ERISA and Environmental Laws) rules, regulations and orders of any Governmental Authority applicable to it.
(i)No failure to satisfy the minimum funding standard applicable to a Plan for a plan year (as described in Section 302 of ERISA and Section 412 of the Internal Revenue Code)

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that could reasonably be expected to have a Material Adverse Effect, whether or not waived, has occurred with respect to any Plan. The Borrower has not incurred, and does not presently expect to incur, any withdrawal liability under Title IV of ERISA with respect to any Multiemployer Plan that could reasonably be expected to have a Material Adverse Effect. The Borrower and each of its ERISA Affiliates have complied in all material respects with ERISA and the Internal Revenue Code. The Borrower and each of its Subsidiaries have complied in all material respects with foreign law applicable to its Foreign Plans, if any. As used herein, the term “Plan” means an “employee pension benefit plan” (as defined in Section 3 of ERISA) which is and has been established or maintained, or to which contributions are or have been made or should be made according to the terms of the plan, by the Borrower or any of its ERISA Affiliates. The term “Multiemployer Plan” means any Plan which is a “multiemployer plan” (as such term is defined in Section 4001(a)(3) of ERISA). The term “Foreign Plan” means any pension, profit-sharing, deferred compensation, or other employee benefit plan, program or arrangement maintained by any Subsidiary which, under applicable local foreign law, is required to be funded through a trust or other funding vehicle.
(j)The Borrower and its Subsidiaries have filed or caused to be filed all material Federal, state and local tax returns that are required to be filed by them, and have paid or caused to be paid all material taxes shown to be due and payable on such returns or on any assessments received by them (to the extent that such taxes and assessments have become due and payable) other than those taxes contested in good faith and for which adequate reserves have been established in accordance with GAAP.
(k)The Borrower is not engaged in the business of extending credit for the purpose of buying or carrying Margin Stock, and no proceeds of any Advance will be used to buy or carry any Margin Stock or to extend credit to others for the purpose of buying or carrying any Margin Stock. Not more than 25% of the assets of the Borrower and the Significant Subsidiaries that are subject to the restrictions of Section 5.02(a), (c) or (d) constitute Margin Stock.
(l)Neither the Borrower nor any of its Significant Subsidiaries is an “investment company,” or an “affiliated person” of, or “promoter” or “principal underwriter” for, an “investment company”, as such terms are defined in the Investment Company Act of 1940, as amended (the “Act”). Neither the making of any Borrowing, the application of the proceeds or repayment thereof by the Borrower nor the consummation of the other transactions contemplated hereby will violate any provision of the Act or any rule, regulation or order of the SEC thereunder.
(m)All Significant Subsidiaries of the Borrower as of the Closing Date are listed on Schedule 4.01(m) hereto.
(n)The Borrower has implemented and maintains in effect policies and procedures designed to ensure compliance by the Borrower, its Subsidiaries and their respective managers, directors, officers, employees and agents with Anti-Corruption Laws and applicable Sanctions, and the Borrower, its Subsidiaries and their respective managers, directors and officers and, to the knowledge of the Borrower, its employees and agents, are in compliance with Anti-Corruption Laws and applicable Sanctions in all material respects and have not engaged in any activity or conduct which would violate Anti-Corruption Laws and applicable Sanctions. None of (i) the Borrower, any Subsidiary or any of their respective managers, directors or officers, or (ii)

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to the knowledge of the Borrower, any employee or agent of the Borrower or any Subsidiary that will act in any capacity in connection with or benefit from the credit facility established hereby, is a Sanctioned Person or located, organized or resident in a Sanctioned Country. No Borrowing or use of proceeds thereof or other transaction contemplated by this Agreement will violate Anti-Corruption Laws or applicable Sanctions.
ARTICLE V
COVENANTS OF THE BORROWER

SECTION 5.01    Affirmative Covenants.
So long as any Advance or any other amount payable hereunder shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will:
(a)Preservation of Existence, Etc. Preserve and maintain, and cause each Significant Subsidiary of the Borrower to preserve and maintain, its corporate, partnership or limited liability company (as the case may be) existence and all material rights (charter and statutory) and franchises; provided, however, that the Borrower and any Significant Subsidiary thereof may consummate any merger or consolidation permitted under Section 5.02(a); and provided further that neither the Borrower nor any Significant Subsidiary thereof shall be required to preserve any right or franchise if (i) the board of directors of the Borrower or such Significant Subsidiary, as the case may be, shall determine that the preservation thereof is no longer desirable in the conduct of the business of the Borrower or such Significant Subsidiary, as the case may be, and that the loss thereof is not disadvantageous in any material respect to the Borrower or such Significant Subsidiary, as the case may be, or to the Lenders; (ii) required in connection with or pursuant to any Restructuring Law; or (iii) required in connection with the RTO Transaction; and provided further, that no Significant Subsidiary shall be required to preserve and maintain its corporate, partnership or limited liability company (as the case may be) existence if (x) the loss thereof is not disadvantageous in any material respect to the Borrower or to the Lenders or (y) required in connection with or pursuant to any Restructuring Law or (z) required in connection with the RTO Transaction.
(b)Compliance with Laws, Etc. Comply, and cause each Significant Subsidiary of the Borrower to comply, in all material respects, with Applicable Law, with such compliance to include, without limitation, compliance with ERISA and Environmental Laws.
(c)Performance and Compliance with Other Agreements. Perform and comply, and cause each Significant Subsidiary of the Borrower to perform and comply, with the provisions of each indenture, credit agreement, contract or other agreement by which it is bound, the non-performance or non-compliance with which would result in a Material Adverse Change.
(d)Inspection Rights. At any reasonable time and from time to time, permit the Administrative Agent or any Lender or any agents or representatives thereof to examine and make copies of and abstracts from the records and books of account of, and visit the properties of, the Borrower and any of its Significant Subsidiaries and to discuss the affairs, finances and accounts of the Borrower and any of its Significant Subsidiaries with any of their respective officers or directors and with their respective independent certified public accountants.

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(e)Maintenance of Properties, Etc. Maintain and preserve, and cause each Significant Subsidiary of the Borrower to maintain and preserve, all of its properties that are used or useful in the conduct of its business in good working order and condition, ordinary wear and tear excepted and except as required in connection with or pursuant to any Restructuring Law or in connection with an RTO Transaction.
(f)Maintenance of Insurance. Maintain, and cause each Significant Subsidiary of the Borrower to maintain, insurance with responsible and reputable insurance companies or associations in such amounts and covering such risks as is usually carried by companies engaged in similar businesses and owning similar properties; provided, however, that the Borrower and each Significant Subsidiary thereof may self-insure to the same extent as other companies engaged in similar businesses and owning similar properties and to the extent consistent with prudent business practice.
(g)Payment of Taxes, Etc. Pay and discharge, and cause each of its Subsidiaries to pay and discharge, before the same shall become delinquent, (i) all taxes, assessments and governmental charges or levies imposed upon it or upon its property and (ii) all lawful claims that, if unpaid, might by law become a Lien upon its property; provided, however, that neither the Borrower nor any of its Subsidiaries shall be required to pay or discharge any such tax, assessment, charge or claim that is being contested in good faith and by proper proceedings and as to which adequate reserves are being maintained in accordance with GAAP, unless and until any Lien resulting therefrom attaches to its property and becomes enforceable against its other creditors.
(h)Keeping of Books. Keep, and cause each Significant Subsidiary of the Borrower to keep, proper books of record and account, in which full and correct entries shall be made of all financial transactions and the assets and business of the Borrower and each such Significant Subsidiary in accordance with GAAP.
(i)Reporting Requirements. Furnish to the Lenders:
(i)as soon as available and in any event within 60 days after the end of each of the first three quarters of each fiscal year of the Borrower, a copy of the Borrower’s Quarterly Report on Form 10-Q for such quarter, as filed with the SEC, which shall contain a consolidated balance sheet of the Borrower and its Subsidiaries as of the end of such quarter and consolidated statements of income and cash flows of the Borrower and its Subsidiaries for the period commencing at the end of the previous fiscal year and ending with the end of such quarter, duly certified (subject to year-end audit adjustments) by the chief financial officer, chief accounting officer, treasurer or assistant treasurer of the Borrower as having been prepared in accordance with GAAP and a certificate of the chief financial officer, chief accounting officer, treasurer or assistant treasurer of the Borrower as to compliance with the terms of this Agreement and (A) certifying that there have been no Subsidiaries that have become Significant Subsidiaries at any time during such period, or any Subsidiaries that have ceased to be Significant Subsidiaries at any time during such period, in each case except as expressly identified in such certificate, and (B) setting forth in reasonable detail the calculations necessary to demonstrate compliance with Section 5.03, provided that in the event of any change in GAAP used in the preparation of such

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financial statements, the Borrower shall also provide, if necessary for the determination of compliance with Section 5.03, a statement of reconciliation conforming such financial statements to GAAP in effect on the Closing Date;
(ii)as soon as available and in any event within 120 days after the end of each fiscal year of the Borrower, a copy of the Borrower’s Annual Report on Form 10-K for such year, as filed with the SEC, which shall contain a copy of the annual audit report for such year for the Borrower and its Subsidiaries containing a consolidated balance sheet of the Borrower and its Subsidiaries as of the end of such fiscal year and consolidated statements of income and cash flows of the Borrower and its Subsidiaries for such fiscal year, in each case accompanied by an opinion by PricewaterhouseCoopers LLP or another independent registered public accounting firm acceptable to the Required Lenders, and consolidating statements of income and cash flows of the Borrower and its Subsidiaries for such fiscal year, and a certificate of the chief financial officer, chief accounting officer, treasurer or assistant treasurer of the Borrower as to compliance with the terms of this Agreement and (A) certifying that there have been no Subsidiaries that have become Significant Subsidiaries at any time during such period, or any Subsidiaries that have ceased to be Significant Subsidiaries at any time during such period, in each case except as expressly identified in such certificate, and (B) setting forth in reasonable detail the calculations necessary to demonstrate compliance with Section 5.03, provided that in the event of any change in GAAP used in the preparation of such financial statements, the Borrower shall also provide, if necessary for the determination of compliance with Section 5.03, a statement of reconciliation conforming such financial statements to GAAP in effect on the Closing Date;
(iii)as soon as possible and in any event within five days after the chief financial officer or treasurer of the Borrower obtains knowledge of the occurrence of each Default continuing on the date of such statement, a statement of the chief financial officer or treasurer of the Borrower setting forth details of such Default and the action that the Borrower has taken and proposes to take with respect thereto;

(iv)promptly after the sending or filing thereof, copies of all Reports on Form 8-K that the Borrower or any Significant Subsidiary files with the SEC or any national securities exchange;

(v)promptly after the commencement thereof, notice of all actions and proceedings before any Governmental Authority or arbitrator affecting the Borrower or any Significant Subsidiary of the type described in Section 4.01(e);

(vi)promptly after request from the Administrative Agent or any Lender, a new Beneficial Ownership Certification or updates, if any, to the information provided in the Beneficial Ownership Certification on or prior to the Closing Date that would result in a change to the list of beneficial owners identified in parts (c) or (d) of such certification; and

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(vii)such other information respecting the Borrower or any of its Subsidiaries as any Lender through the Administrative Agent may from time to time reasonably request.

Notwithstanding the foregoing, the information required to be delivered pursuant to clauses (i), (ii) and (iv) shall be deemed to have been delivered if such information shall be available on the website of the SEC at http://www.sec.gov, the website of AEP at http://www.aep.com or, in each case, any successor website; provided that the compliance certificates required under clauses (i) and (ii) shall be delivered in the manner specified in Section 8.02(b).

(j)Compliance with Anti-Corruption Laws and Sanctions. Maintain in effect and enforce policies and procedures designed to ensure compliance by the Borrower, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws and applicable Sanctions.
SECTION 5.02    Negative Covenants.
So long as any Advance or any other amount payable hereunder shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower agrees that it will not:
(a)Mergers, Etc. Merge or consolidate with or into any Person, or permit any Significant Subsidiary to do so, except that (i) any Subsidiary may merge or consolidate with or into any other Subsidiary of the Borrower, (ii) any Subsidiary may merge into the Borrower, (iii) any Significant Subsidiary may merge with or into any other Person so long as such Significant Subsidiary continues to be a Significant Subsidiary of the Borrower and (iv) the Borrower may merge with any other Person so long as the successor entity (x) is the Borrower and (y) has long-term senior unsecured debt ratings issued (and confirmed after giving effect to such merger) by S&P or Moody’s of at least BBB- and Baa3, respectively (or if no such ratings have been issued, commercial paper ratings issued (and confirmed after giving effect to such merger) by S&P and Moody’s of at least A-3 and P-3, respectively), provided, in each case, that no Default shall have occurred and be continuing at the time of such proposed transaction or would result therefrom.
(b)Stock of Significant Subsidiaries. Sell, lease, transfer or otherwise dispose of, other than (i) in connection with an RTO Transaction, but only if no Default or Event of Default has occurred and is continuing or would result from such RTO Transaction, or (ii) pursuant to the requirements of any Restructuring Law, equity interests in any Significant Subsidiary of the Borrower if such Significant Subsidiary would cease to be a Subsidiary as a result of such sale, lease, transfer or disposition.
(c)Sales, Etc. of Assets. Sell, lease, transfer or otherwise dispose of, or permit any Significant Subsidiary to sell, lease, transfer or otherwise dispose of, any assets, or grant any option or other right to purchase, lease or otherwise acquire any assets, except (i) sales in the ordinary course of its business, (ii) sales, leases, transfers or dispositions of assets to any Person that is not a wholly-owned Subsidiary of the Borrower that in the aggregate do not exceed 20% of the Consolidated Tangible Net Assets of the Borrower and its Subsidiaries, whether in one transaction or a series of transactions, (iii) other sales, leases, transfers and dispositions made in connection with an RTO Transaction or pursuant to the requirements of any Restructuring Law or

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to a wholly owned Subsidiary of the Borrower, or (iv) sales of pollution control assets to a state or local government or any political subdivision or agency thereof in connection with any transaction with such Person pursuant to which such Person sells or otherwise transfers such pollution control assets back to the Borrower or a Subsidiary under an installment sale, loan or similar agreement, in each case in connection with the issuance of pollution control or similar bonds.
(d)Liens, Etc. Create or suffer to exist, or permit any Significant Subsidiary to create or suffer to exist, any Lien on or with respect to any of its properties, including, without limitation, on or with respect to equity interests in any Subsidiary of the Borrower, whether now owned or hereafter acquired, or assign, or permit any Significant Subsidiary to assign, any right to receive income (other than in connection with Stranded Cost Recovery Bonds and the sale of accounts receivable by the Borrower), other than (i) Permitted Liens, (ii) the Liens existing on the Closing Date, (iii) Liens securing first mortgage bonds issued by the Borrower or any Subsidiary of the Borrower the rates or charges of which are regulated by the Federal Energy Regulatory Commission or any state governmental authority, provided that the aggregate principal amount of such first mortgage bonds of the Borrower or any such Subsidiary do not exceed 66 2/3% of the net value of plant, property and equipment of the Borrower or such Subsidiary, as applicable, and (iv) the replacement, extension or renewal of any Lien permitted by clauses (ii) and (iii) above upon or in the same property theretofore subject thereto or the replacement, extension or renewal (without increase in the amount or change in any direct or contingent obligor) of the Debt secured thereby.
(e)Restrictive Agreements. Enter into, or permit any Significant Subsidiary to enter into (except in connection with or pursuant to any Restructuring Law), any agreement after the Closing Date, or amend, supplement or otherwise modify any agreement existing on the Closing Date, that imposes any restriction on the ability of any Significant Subsidiary to make payments, directly or indirectly, to its shareholders by way of dividends, advances, repayment of loans or intercompany charges, expenses and accruals or other returns on investments that is more restrictive than any such restriction applicable to such Significant Subsidiary on the Closing Date; provided, however, that any Significant Subsidiary may agree to a financial covenant limiting its ratio of Consolidated Debt to Consolidated Capital to no more than 0.675 to 1.000.
(f)ERISA. (i) Terminate or withdraw from, or permit any of its ERISA Affiliates to terminate or withdraw from, any Plan with respect to which the Borrower or any of its ERISA Affiliates may have any liability by reason of such termination or withdrawal, if such termination or withdrawal could have a Material Adverse Effect, (ii) incur a full or partial withdrawal, or permit any ERISA Affiliate to incur a full or partial withdrawal, from any Multiemployer Plan with respect to which the Borrower or any of its ERISA Affiliates may have any liability by reason of such withdrawal, if such withdrawal could have a Material Adverse Effect, (iii) otherwise fail, or permit any of its ERISA Affiliates to fail, to comply in all material respects with ERISA or the related provisions of the Internal Revenue Code if such noncompliances, singly or in the aggregate, could have a Material Adverse Effect, or (iv) fail, or permit any of its Subsidiaries to fail, to comply with Applicable Law with respect to any Foreign Plan if such noncompliances, singly or in the aggregate, could have a Material Adverse Effect.
(g)Use of Proceeds. Use the proceeds of any Borrowing to buy or carry Margin Stock.

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(h)No Violation of Anti-Corruption Laws and Sanctions. Request any Borrowing, or use or permit any of its Subsidiaries or its or their respective directors, officers, employees and agents to use, directly or, to the actual knowledge of the Borrower or any of its Subsidiaries, indirectly, any proceeds of any Borrowing (i) in furtherance of an offer, payment, promise to pay, or authorization of the payment or giving of money, or anything else of value, to any Person in violation of any Anti-Corruption Laws, (ii) for the purpose of funding, financing or facilitating any activities, business or transaction of or with any Sanctioned Person, or in any Sanctioned Country, or (iii) in any manner that would result in the violation of any Sanctions applicable to any party hereto.
SECTION 5.03    Financial Covenant.
So long as any Advance shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will maintain a ratio of Consolidated Debt to Consolidated Capital, as of the last day of each March, June, September and December, of not greater than 0.675 to 1.000.
ARTICLE VI
EVENTS OF DEFAULT

SECTION 6.01    Events of Default.
If any of the following events (“Events of Default”) shall occur and be continuing:
(a)The Borrower (i) shall fail to pay any principal of any Advance when the same becomes due and payable, or (ii) shall fail to pay any interest on any Advance or make any other payment of fees or other amounts payable under this Agreement within five days after the same becomes due and payable; or
(b)Any representation or warranty made by the Borrower herein or by the Borrower (or any of its officers) in connection with this Agreement shall prove to have been incorrect in any material respect when made; or
(c)(i) The Borrower shall fail to perform or observe any term, covenant or agreement contained in Section 5.01(a), 5.01(i)(iii) or 5.02 (other than Section 5.02(f)), or (ii) the Borrower shall fail to perform or observe any other term, covenant or agreement contained in this Agreement or any other Loan Document if such failure shall remain unremedied for 30 days after written notice thereof shall have been given to the Borrower by the Administrative Agent or any Lender; or
(d)Any event shall occur or condition shall exist under any agreement or instrument relating to Debt of the Borrower (but excluding Debt outstanding hereunder) or any Significant Subsidiary of the Borrower outstanding in a principal or notional amount of at least $50,000,000 in the aggregate if the effect of such event or condition is to accelerate or require early termination of the maturity or tenor of such Debt, or any such Debt shall be declared to be due and payable, or required to be prepaid or redeemed (other than by a regularly scheduled required prepayment or redemption), terminated, purchased or defeased, or an offer to prepay, redeem, purchase or defease such Debt shall be required to be made, in each case prior to the stated maturity or the original tenor thereof; or

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(e)The Borrower or any Significant Subsidiary of the Borrower shall generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make a general assignment for the benefit of creditors; or any proceeding shall be instituted by or against the Borrower or any Significant Subsidiary of the Borrower seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, custodian or other similar official for it or for any substantial part of its property and, in the case of any such proceeding instituted against it (but not instituted by it), either such proceeding shall remain undismissed or unstayed for a period of 60 days, or any of the actions sought in such proceeding (including, without limitation, the entry of an order for relief against, or the appointment of a receiver, trustee, custodian or other similar official for, it or for any substantial part of its property) shall occur; or the Borrower or any Significant Subsidiary of the Borrower shall take any corporate action to authorize any of the actions set forth above in this subsection (e); or
(f)(i) Any entity, person (within the meaning of Section 14(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) that as of the Closing Date was beneficial owner (as defined in Rule 13d-3 under the Exchange Act) of less than 30% of the Voting Stock of AEP shall acquire a beneficial ownership (within the meaning of Rule 13d-3 of the SEC under the Exchange Act), directly or indirectly, of Voting Stock of AEP (or other securities convertible into such Voting Stock) representing 30% or more of the combined voting power of all Voting Stock of AEP; (ii) during any period of up to 24 consecutive months, commencing after the Closing Date, individuals who at the beginning of such 24-month period were directors of AEP shall cease for any reason to constitute a majority of the board of directors of AEP, provided that any person becoming a director subsequent to the Closing Date, whose election, or nomination for election by AEP’s shareholders, was approved by a vote of at least a majority of the directors of the board of directors of AEP as comprised as of the Closing Date shall be, for purposes of this provision, considered as though such person were a member of the board as of the Closing Date; or (iii) AEP shall fail to own directly or indirectly 100% of the Voting Stock of the Borrower; or
(g)Any judgment or order for the payment of money in excess of $50,000,000 in the case of the Borrower or any Significant Subsidiary of the Borrower to the extent not paid or insured shall be rendered against the Borrower or any Significant Subsidiary of the Borrower and either (i) enforcement proceedings shall have been commenced by any creditor upon such judgment or order or (ii) there shall be any period of 30 consecutive days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect; or
(h)(i) The termination of or withdrawal from the United Mine Workers’ of America 1974 Pension Trust by AEP or any of its ERISA Affiliates shall have occurred and the liability of AEP and its ERISA Affiliates related to such termination or withdrawal exceeds $75,000,000 in the aggregate; or (ii) any other ERISA Event shall have occurred and the liability of the Borrower and its ERISA Affiliates related to such ERISA Event exceeds $50,000,000;

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then, and in any such event, the Administrative Agent (i) shall at the request, or may with the consent, of the Required Lenders, by notice to the Borrower, declare the obligation of each Lender to make Advances to be terminated, whereupon the same shall forthwith terminate, and (ii) shall at the request, or may with the consent, of the Required Lenders, by notice to the Borrower, declare the outstanding Advances, all interest thereon and all other amounts payable under this Agreement to be forthwith due and payable, whereupon the outstanding Advances, all such interest and all such amounts shall become and be forthwith due and payable by the Borrower, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by the Borrower; provided, however, that in the event of an actual or deemed entry of an order for relief with respect to the Borrower or any Significant Subsidiary of the Borrower under the Bankruptcy Code of the United States of America, (A) the obligation of each Lender to make Advances shall automatically be terminated and (B) the outstanding Advances, all such interest and all such amounts shall automatically become and be due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by the Borrower.
ARTICLE VII
THE ADMINISTRATIVE AGENT

SECTION 7.01    Appointment and Authorization.
Each Lender hereby irrevocably appoints and authorizes the Administrative Agent to enter into each of the Loan Documents to which it is a party (other than this Agreement) on its behalf and to take such actions as Administrative Agent on its behalf and to exercise such powers under the Loan Documents as are delegated to Administrative Agent by the terms thereof, together with all such powers as are reasonably incidental thereto. Subject to the terms of Section 8.01 and to the terms of the other Loan Documents, Administrative Agent is authorized and empowered to amend, modify, or waive any provisions of this Agreement or the other Loan Documents on behalf of Lenders. The provisions of this Article 7 are solely for the benefit of Administrative Agent and Lenders and Borrower shall not have any rights as a third party beneficiary of any of the provisions hereof. In performing its functions and duties under this Agreement, Administrative Agent shall act solely as agent of Lenders and does not assume and shall not be deemed to have assumed any obligation toward or relationship of agency or trust with or for Borrower. Administrative Agent may perform any of its duties hereunder, or under the Loan Documents, by or through its own agents or employees.
SECTION 7.02    Administrative Agent and Affiliates.
Administrative Agent shall have the same rights and powers under the Loan Documents as any other Lender and may exercise or refrain from exercising the same as though it were not Administrative Agent, and Administrative Agent and its Affiliates may lend money to, invest in and generally engage in any kind of business with Borrower or any Affiliate of Borrower as if it were not Administrative Agent hereunder.
SECTION 7.03    Action by Administrative Agent.

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The duties of Administrative Agent shall be mechanical and administrative in nature. Administrative Agent shall not have by reason of this Agreement a fiduciary relationship in respect of any Lender. Nothing in this Agreement or any of the Loan Documents is intended to or shall be construed to impose upon Administrative Agent any obligations in respect of this Agreement or any of the Loan Documents except as expressly set forth herein or therein.
SECTION 7.04    Consultation with Experts.
Administrative Agent may consult with legal counsel, independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken by it in good faith in accordance with the advice of such counsel, accountants or experts.
SECTION 7.05    Liability of Administrative Agent.
Neither Administrative Agent nor any of its directors, officers, agents or employees shall be liable to any Lender for any action taken or not taken by it in connection with the Loan Documents, except that Administrative Agent shall be liable with respect to its specific duties set forth hereunder, but only to the extent of its own gross negligence or willful misconduct in the discharge thereof as determined by a final non-appealable judgment of a court of competent jurisdiction. Neither Administrative Agent nor any of its directors, officers, agents or employees shall be responsible for or have any duty to ascertain, inquire into or verify (i) any statement, warranty or representation made in connection with any Loan Document or any borrowing hereunder; (ii) the performance or observance of any of the covenants or agreements specified in any Loan Document; (iii) the satisfaction of any condition specified in any Loan Document; (iv) the validity, effectiveness, sufficiency or genuineness of any Loan Document, any Lien purported to be created or perfected thereby or any other instrument or writing furnished in connection therewith; (v) the existence or non-existence of any Default or Event of Default; or (vi) the financial condition of Borrower. Administrative Agent shall not incur any liability by acting in reliance upon any notice, consent, certificate, statement, or other writing (which may be a bank wire, telex, facsimile or electronic transmission or similar writing) believed by it to be genuine or to be signed by the proper party or parties. Administrative Agent shall not be liable for any apportionment or distribution of payments made by it in good faith and if any such apportionment or distribution is subsequently determined to have been made in error the sole recourse of any Lender to whom payment was due but not made, shall be to recover from other Lenders any payment in excess of the amount to which they are determined to be entitled (and such other Lenders hereby agree to return to such Lender any such erroneous payments received by them).
SECTION 7.06    Indemnification.
Each Lender severally agrees to indemnify the Administrative Agent and each of its Related Parties (to the extent not promptly reimbursed by the Borrower and without limiting its obligation to do so) from and against such Lender’s ratable share (determined as provided below) of any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever that may be imposed on, incurred by, or asserted against the Administrative Agent or such Related Party in any way relating to or arising out of this Agreement or any action taken or omitted by such Person under this Agreement;

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provided, however, that no Lender shall be liable, as to the Administrative Agent or any of its Related Parties, for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the gross negligence or willful misconduct of such Person as determined in a final, non-appealable judgment by a court of competent jurisdiction. Without limitation of the foregoing, each Lender agrees to reimburse the Administrative Agent and each of its Related Parties promptly upon demand for its ratable share of any costs and expenses (including, without limitation, fees and reasonable expenses of counsel) payable by the Borrower under Section 8.04, to the extent that the Administrative Agent or such Related Party is not promptly reimbursed for such costs and expenses by the Borrower after request therefor and without limiting the Borrower’s obligation to do so. For purposes of this Section 7.06, the Lenders’ respective ratable shares of any amount shall be determined, at any time, according to the sum of (i) the aggregate principal amount of the Advances outstanding at such time and owing to the respective Lenders and (ii) the aggregate unused portions of their respective Commitments at such time. In the event that any Lender shall have failed to make any Advance as required hereunder, such Lender’s Commitment shall be considered to be unused for purposes of this Section 7.06 to the extent of the amount of such Advance. The failure of any Lender to reimburse the Administrative Agent or any of its Related Parties promptly upon demand for its ratable share of any amount required to be paid by the Lender to the Administrative Agent or such Related Party as provided herein shall not relieve any other Lender of its obligation hereunder to reimburse the Administrative Agent or such Related Party for its ratable share of such amount, but no Lender shall be responsible for the failure of any other Lender to reimburse the Administrative Agent or such Related Party for such other Lender’s ratable share of such amount.
If any indemnity furnished to Administrative Agent for any purpose shall, in the opinion of Administrative Agent, be insufficient or become impaired, Administrative Agent may call for additional indemnity and cease, or not commence, to do the acts indemnified against even if so directed by Required Lenders until such additional indemnity is furnished.
Without prejudice to the survival of any other agreement of any Lender hereunder, the agreement and obligations of each Lender contained in this Section 7.06 shall survive the payment in full of principal, interest and all other amounts payable hereunder.
SECTION 7.07    Right to Request and Act on Instructions.
Administrative Agent may at any time request instructions from Lenders with respect to any actions or approvals which by the terms of this Agreement or of any of the Loan Documents Administrative Agent is permitted or desires to take or to grant, and if such instructions are promptly requested, Administrative Agent shall be absolutely entitled to refrain from taking any action or to withhold any approval and shall not be under any liability whatsoever to any Person for refraining from any action or withholding any approval under any of the Loan Documents until it shall have received such instructions from Required Lenders or all or such other portion of the Lenders as shall be prescribed by this Agreement. Without limiting the foregoing, no Lender shall have any right of action whatsoever against Administrative Agent as a result of Administrative Agent acting or refraining from acting under this Agreement or any of the other Loan Documents in accordance with the instructions of Required Lenders (or all or such other portion of the Lenders as shall be prescribed by this Agreement) and, notwithstanding the instructions of Required Lenders (or such other applicable portion of the Lenders), Administrative Agent shall have no

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obligation to take any action if it believes, in good faith, that such action would violate Applicable Law or exposes Administrative Agent to any liability for which it has not received satisfactory indemnification in accordance with the provisions of Section 7.06.
SECTION 7.08    Credit Decision.
Each Lender acknowledges that it has, independently and without reliance upon Administrative Agent or any other Lender, and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon Administrative Agent or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking any action under the Loan Documents.
SECTION 7.09    Notice of Default.
Administrative Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Event of Default except with respect to defaults in the payment of principal, interest and fees required to be paid to Administrative Agent for the account of Lenders, unless Administrative Agent shall have received written notice from a Lender or Borrower referring to this Agreement, describing such Default or Event of Default and stating that such notice is a “notice of default”. Administrative Agent will notify each Lender of its receipt of any such notice. Administrative Agent shall take such action with respect to such Default or Event of Default as may be requested by Required Lenders (or all or such other portion of the Lenders as shall be prescribed by this Agreement) in accordance with the terms hereof. Unless and until Administrative Agent has received any such request, Administrative Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default or Event of Default as it shall deem advisable or in the best interests of Lenders.
SECTION 7.10    Successor Administrative Agent.
Administrative Agent may at any time give notice of its resignation to the Lenders and Borrower. Upon receipt of any such notice of resignation, Required Lenders shall have the right, in consultation with Borrower, to appoint a successor Administrative Agent. Upon the acceptance of a successor’s appointment as Administrative Agent hereunder and notice of such acceptance to the retiring Administrative Agent, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring (or retired) Administrative Agent, the retiring Administrative Agent’s resignation shall become immediately effective and the retiring Administrative Agent shall be discharged from all of its duties and obligations hereunder and under the other Loan Documents (if such resignation was not already effective and such duties and obligations not already discharged, as provided below in this paragraph). The fees payable by Borrower to a successor Administrative Agent shall be the same as those payable to its predecessor unless otherwise agreed between Borrower and such successor. If no such successor shall have been so appointed by Required Lenders and shall have accepted such appointment within thirty (30) days after the retiring Administrative Agent gives notice of its resignation, then the retiring Administrative Agent may on behalf of the Lenders (but without any obligation) appoint a successor Administrative Agent. From and following the expiration of such thirty (30) day period,

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Administrative Agent shall have the exclusive right, upon one (1) Business Days’ notice to Borrower and the Lenders, to make its resignation effective immediately. From and following the effectiveness of such notice, (i) the retiring Administrative Agent shall be discharged from its duties and obligations hereunder and under the other Loan Documents and (ii) all payments, communications and determinations provided to be made by, to or through Administrative Agent shall instead be made by or to each Lender directly, until such time as Required Lenders appoint a successor Administrative Agent as provided for above in this paragraph. The provisions of this Agreement shall continue in effect for the benefit of any retiring Administrative Agent and its sub-agents after the effectiveness of its resignation hereunder and under the other Loan Documents in respect of any actions taken or omitted to be taken by any of them while the retiring Administrative Agent was acting or was continuing to act as Administrative Agent.
SECTION 7.11    Return of Payments.
If Administrative Agent pays an amount to a Lender under this Agreement in the belief or expectation that a related payment has been or will be received by Administrative Agent from Borrower and such related payment is not received by Administrative Agent, then Administrative Agent will be entitled to recover such amount from such Lender on demand without setoff, counterclaim or deduction of any kind, together with interest accruing on a daily basis at the Federal Funds Rate.
If Administrative Agent determines at any time that any amount received by Administrative Agent under this Agreement must be returned to Borrower or paid to any other Person pursuant to any insolvency law or otherwise, then, notwithstanding any other term or condition of this Agreement or any other Loan Document, Administrative Agent will not be required to distribute any portion thereof to any Lender. In addition, each Lender will repay to Administrative Agent on demand any portion of such amount that Administrative Agent has distributed to such Lender, together with interest at such rate, if any, as Administrative Agent is required to pay to Borrower or such other Person, without setoff, counterclaim or deduction of any kind.
SECTION 7.12    Defaulting Lenders.
The failure of any Defaulting Lender to make any Advance or any payment required by it hereunder shall not relieve any other Lender of its obligations to make such Advance or payment, but neither any other Lender nor Administrative Agent shall be responsible for the failure of any Defaulting Lender to make an Advance or make any other payment required hereunder.
SECTION 7.13    Sharing of Payments
If any Lender shall obtain any payment or other recovery (whether voluntary, involuntary, by application of setoff or otherwise) on account of any Loan (other than pursuant to the terms of Section 8.16) in excess of its pro rata share of payments entitled pursuant to the other provisions of this Section 7.13, such Lender shall purchase from the other Lenders such participations in extensions of credit made by such other Lenders (without recourse, representation or warranty) as shall be necessary to cause such purchasing Lender to share the excess payment or other recovery ratably with each of them; provided, however, that if all or any portion of the excess payment or

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other recovery is thereafter required to be returned or otherwise recovered from such purchasing Lender, such portion of such purchase shall be rescinded and each Lender which has sold a participation to the purchasing Lender shall repay to the purchasing Lender the purchase price to the ratable extent of such return or recovery, without interest. Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this clause (e) may, to the fullest extent permitted by law, exercise all its rights of payment with respect to such participation as fully as if such Lender were the direct creditor of Borrower in the amount of such participation. If under any applicable bankruptcy, insolvency or other similar law, any Lender receives a secured claim in lieu of a setoff to which this clause (e) applies, such Lender shall, to the extent practicable, exercise its rights in respect of such secured claim in a manner consistent with the rights of the Lenders entitled under this clause (e) to share in the benefits of any recovery on such secured claim.
SECTION 7.14    Right to Perform, Preserve and Protect.
If Borrower fails to perform any obligation hereunder or under any other Loan Document, Administrative Agent itself may, but shall not be obligated to, cause such obligation to be performed at Borrower’s expense. Administrative Agent is further authorized by Borrower and the Lenders to make expenditures from time to time which Administrative Agent, in its reasonable business judgment, deems necessary or desirable to (i) preserve or protect the business conducted by Borrower or any portion thereof and/or (ii) enhance the likelihood of, or maximize the amount of, repayment of the Advances. Borrower hereby agrees to reimburse Administrative Agent on demand for any and all costs, liabilities and obligations incurred by Administrative Agent pursuant to this Section 7.14. Each Lender hereby agrees to indemnify Administrative Agent upon demand for any and all costs, liabilities and obligations incurred by Administrative Agent pursuant to this Section 7.14 and all such amounts shall be deemed to be included within and covered by the Borrower’s indemnification obligation more particularly described in Section 8.04(b) of this Agreement.
SECTION 7.15    Additional Titled Agents.
Except for rights and powers, if any, expressly reserved under this Agreement to any bookrunner, arranger or to any titled agent named on the cover page of this Agreement, other than Administrative Agent (collectively, the “Additional Titled Agents”), and except for obligations, liabilities, duties and responsibilities, if any, expressly assumed under this Agreement by any Additional Titled Agent, no Additional Titled Agent, in such capacity, has any rights, powers, liabilities, duties or responsibilities hereunder or under any of the other Loan Documents. Without limiting the foregoing, no Additional Titled Agent shall have nor be deemed to have a fiduciary relationship with any Lender. At any time that any Lender serving as an Additional Titled Agent shall have transferred to any other Person (other than any Affiliates) all of its interests in the Advances and in the Commitment, such Lender shall be deemed to have concurrently resigned as such Additional Titled Agent.
ARTICLE VIII
MISCELLANEOUS

SECTION 8.01    Amendments, Etc.

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Subject to Section 8.16(a)(i), no amendment or waiver of any provision of this Agreement, nor consent to any departure by the Borrower therefrom, shall in any event be effective unless the same shall be in writing and signed by the Required Lenders and the Borrower, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided, however, that no amendment, waiver or consent shall (a) unless in writing and signed by all the Lenders (other than, in the case of the following clauses (i), (iii) and (iv), any Defaulting Lender), do any of the following: (i) amend Section 3.01 or 3.02 or waive any of the conditions specified therein, (ii) increase the aggregate amount of the Commitments, (iii) change the definition of Required Lenders or the percentage of the Commitments or of the aggregate unpaid principal amount of the outstanding Borrowings, or the number or percentage of the Lenders, that shall be required for the Lenders or any of them to take any action hereunder, or (iv) amend or waive this Section 8.01 or any provision of this Agreement that requires pro rata treatment of the Lenders; or (b) unless in writing and signed by each Lender that is directly affected thereby, do any of the following: (1) increase the amount or extend the termination date of such Lender’s Commitment, or subject such Lender to any additional obligations, (2) reduce the principal of, or interest on, or rate of interest applicable to, the outstanding Advances of such Lender or any fees or other amounts payable to such Lender hereunder, or (3) postpone any date fixed for any payment of principal of, or interest on, the outstanding Advances or any fees or other amounts payable to such Lender hereunder; and provided further that (x) no amendment, waiver or consent shall, unless in writing and signed by the Administrative Agent in addition to the Lenders required above to take such action, affect the rights or duties of the Administrative Agent under this Agreement, and (y) no amendment, waiver or consent shall, unless in writing and signed by the Administrative Agent and the Required Lenders, amend or waive Section 8.16. Notwithstanding the foregoing, any provision of this Agreement may be amended by an agreement in writing entered into by the Borrower, the Required Lenders and the Administrative Agent if (i) by the terms of such agreement the Commitment of each Lender not consenting to the amendment provided for therein shall terminate (but such Lender shall continue to be entitled to the benefits of Sections 2.11, 2.14 and 8.04) upon the effectiveness of such amendment and (ii) at the time such amendment becomes effective, each Lender not consenting thereto receives payment in full of the principal outstanding amount of and interest accrued on each Advance made by it and outstanding and all other amounts owing to it or accrued for its account under this Agreement and is released from its obligations hereunder.
SECTION 8.02    Notices, Etc.
(a)The Borrower hereby agrees that any notice that is required to be delivered to it hereunder shall be delivered to the Borrower as set forth in this Section 8.02. All notices and other communications provided for hereunder shall be in writing (including fax) and mailed, faxed or delivered, if to the Borrower at its address at 1 Riverside Plaza, Columbus, Ohio 43215, Attention: Treasurer (fax: 614-716-2807; telephone: 614-716-2663), with a copy to the General Counsel (fax: 614-716-3440; telephone: 614-716-2929) and to corporatefinance@aep.com; if to any Initial Lender, at its Domestic Lending Office specified in its Administrative Questionnaire; if to any other Lender, at its Domestic Lending Office specified in the Assignment and Assumption pursuant to which it became a Lender; if to the Administrative Agent, at its address at (i) Sumitomo Mitsui Banking Corporation, 277 Park Avenue, New York, New York 10172, Attention: Agency Loan Services Department, telephone: 212-256-7317, facsimile: 212-224-4501 and email: AgencyServices@smbcgroup.com and cmragency@smbcgroup.com, (ii) for notices and

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communications relating to compliance with the covenants hereunder, Sumitomo Mitsui Banking Corporation, 277 Park Avenue, New York, New York 10172, Attention: Agency Loan Services Department, telephone: 212-256-7317, facsimile: 212-224-4501 and email: AgencyServices@smbcgroup.com and cmragency@smbcgroup.com; or, as to the Borrower or the Administrative Agent, at such other address as shall be designated by such party in a written notice to the other parties and, as to each other party, at such other address as shall be designated by such party in a written notice to the Borrower and the Administrative Agent. All such notices and communications shall be effective when delivered or received at the appropriate address or number to the attention of the appropriate individual or department, except that notices and communications to the Administrative Agent pursuant to Article II, III or VII shall not be effective until received by the Administrative Agent. Delivery by fax or electronic transmission of an executed counterpart of any amendment or waiver of any provision of this Agreement or of any Exhibit hereto to be executed and delivered hereunder shall be effective as delivery of a manually executed counterpart thereof.
(b)The Borrower and each Lender hereby agrees that the Administrative Agent may make any information required to be delivered under Section 5.01(i)(i), (ii), (iv) and (v) (the “Communications”) available to the Lenders by posting the Communications on Intralinks, SyndTrak or a substantially similar electronic transmission system (the “Platform”). The Borrower and each Lender hereby acknowledges that the distribution of material through an electronic medium is not necessarily secure and that there are confidentiality and other risks associated with such distribution.
(c)THE PLATFORM IS PROVIDED “AS IS” AND “AS AVAILABLE”. THE AGENT PARTIES (AS DEFINED BELOW) DO NOT WARRANT, AND SHALL NOT BE DEEMED TO WARRANT, THE ACCURACY OR COMPLETENESS OF THE COMMUNICATIONS, OR THE ADEQUACY OF THE PLATFORM AND EXPRESSLY DISCLAIM LIABILITY FOR ERRORS OR OMISSIONS IN THE COMMUNICATIONS. NO WARRANTY OF ANY KIND, EXPRESS, IMPLIED OR STATUTORY, INCLUDING, WITHOUT LIMITATION, ANY WARRANTY OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, NON-INFRINGEMENT OF THIRD-PARTY RIGHTS OR FREEDOM FROM VIRUSES OR OTHER CODE DEFECTS, IS MADE, OR SHALL BE DEEMED TO BE MADE, BY THE AGENT PARTIES IN CONNECTION WITH THE COMMUNICATIONS OR THE PLATFORM. IN NO EVENT SHALL THE ADMINISTRATIVE AGENT OR ANY OF ITS RELATED PARTIES (COLLECTIVELY, “AGENT PARTIES”) HAVE ANY LIABILITY TO THE BORROWER, ANY LENDER OR ANY OTHER PERSON OR ENTITY FOR DAMAGES OF ANY KIND, INCLUDING, WITHOUT LIMITATION, DIRECT OR INDIRECT, SPECIAL, INCIDENTAL OR CONSEQUENTIAL DAMAGES (INCLUDING LOST PROFITS), LOSSES OR EXPENSES (WHETHER IN TORT, CONTRACT OR OTHERWISE) ARISING OUT OF THE BORROWER’S OR THE ADMINISTRATIVE AGENT’S TRANSMISSION OF COMMUNICATIONS THROUGH THE INTERNET, EXCEPT TO THE EXTENT THE LIABILITY OF ANY AGENT PARTY IS FOUND IN A FINAL, NON-APPEALABLE JUDGMENT BY A COURT OF COMPETENT JURISDICTION TO HAVE RESULTED PRIMARILY FROM SUCH AGENT PARTY’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

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The Administrative Agent agrees that the receipt of the Communications by the Administrative Agent at its e-mail address set forth above shall constitute effective delivery of the Communications to the Administrative Agent for purposes of the Loan Documents. Each Lender agrees that notice to it (as provided in the next sentence) specifying that the Communications have been posted to the Platform shall constitute effective delivery of the Communications to such Lender for purposes of the Loan Documents. Each Lender agrees (i) to notify the Administrative Agent in writing (including by electronic communication) from time to time of such Lender’s e-mail address to which the foregoing notice may be sent by electronic transmission and (ii) that the foregoing notice may be sent to such e-mail address.
Nothing herein shall prejudice the right of the Administrative Agent or any Lender to give any notice or other communication pursuant to any Loan Document in any other manner specified in such Loan Document.
SECTION 8.03    No Waiver; Remedies.
No failure on the part of any Lender or the Administrative Agent to exercise, and no delay in exercising, any right or power hereunder or under any other Loan Document shall operate as a waiver thereof; nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such a right or power, preclude any other or further exercise thereof or the exercise of any other right or power. The rights and remedies of the Administrative Agent and the Lenders hereunder and under the other Loan Documents are cumulative and not exclusive of any rights and remedies that are provided by law or that they would otherwise have.
SECTION 8.04    Costs and Expenses; Indemnification.
(a)The Borrower agrees to pay promptly upon demand all reasonable out-of-pocket costs and expenses of the Administrative Agent and the Arrangers in connection with the preparation, execution, delivery, administration, modification and amendment of this Agreement and the other documents to be delivered hereunder, including, without limitation, (i) all due diligence, syndication (including printing, distribution and bank meetings), transportation, computer, electronic data site, duplication, appraisal, consultant, and audit expenses and (ii) the reasonable fees and expenses of counsel for the Administrative Agent with respect thereto and with respect to advising the Administrative Agent as to its rights and responsibilities under this Agreement. The Borrower further agrees to pay promptly upon demand all costs and expenses of the Administrative Agent and the Lenders, if any (including, without limitation, counsel fees and expenses), in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Agreement and the other documents to be delivered hereunder, including, without limitation, reasonable fees and expenses of counsel for the Administrative Agent and the Lenders in connection with the enforcement of rights under this Section 8.04(a).
(b)The Borrower agrees to indemnify and hold harmless each Lender, the Arrangers and the Administrative Agent and each of their Related Parties (each, an “Indemnified Party”) from and against any and all claims, damages, losses, liabilities and penalties, joint or several, to which any such Indemnified Party may become subject, in each case arising out of or in connection with or relating to (including, without limitation, in connection with any actual or

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prospective claim, investigation, litigation or proceeding or preparation of a defense in connection therewith) (i) the execution or delivery of this Agreement, any of the transactions contemplated herein or the actual or proposed use of the proceeds of the Advances, (ii) any error or omission in connection with posting of data (x) required to be delivered pursuant to Section 5.01(i)(i), (ii) or (iv) on the website of the SEC or any successor website or (y) on the Platform, or (iii) the actual or alleged presence of Hazardous Materials on any property of the Borrower or any of its Subsidiaries or any Environmental Action relating in any way to the Borrower or any of its Subsidiaries, and to reimburse any Indemnified Party for any and all reasonable expenses (including, without limitation, reasonable fees and expenses of counsel) as they are incurred in connection with the investigation of or preparation for or defense of any pending or threatened actual or prospective claim or any action or proceeding arising therefrom, whether or not such Indemnified Party is a party and whether or not such claim, action or proceeding is initiated or brought by or on behalf of the Borrower or any of its Affiliates and whether or not any of the transactions contemplated hereby are consummated or this Agreement is terminated, AND THE FOREGOING INDEMNIFICATION SHALL APPLY WHETHER OR NOT SUCH INDEMNIFIED LIABILITIES ARE IN ANY WAY OR TO ANY EXTENT OWED, IN WHOLE OR IN PART, UNDER ANY CLAIM OR THEORY OF STRICT LIABILITY, OR ARE CAUSED, IN WHOLE OR IN PART, BY ANY NEGLIGENT ACT OR OMISSION OF ANY KIND BY ANY INDEMNIFIED PERSON, except to the extent such claim, damage, loss, liability, penalty or expense is found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from such Indemnified Party’s gross negligence or willful misconduct. In the case of an investigation, litigation or other proceeding to which the indemnity in this Section 8.04(b) applies, such indemnity shall be effective whether or not such investigation, litigation or proceeding is brought by the Borrower, its managers, shareholders or creditors or an Indemnified Party or any other Person or any Indemnified Party is otherwise a party thereto and whether or not the transactions contemplated hereby are consummated. To the fullest extent permitted by applicable law, the Borrower agrees not to assert, or permit any of their Affiliates or Related Parties to assert, and each hereby waives, any claim against any Indemnified Party on any theory of liability, for special, indirect, or punitive damages (as opposed to direct or actual damages) arising out of or otherwise relating to this Agreement, any of the transactions contemplated herein or the actual or proposed use of the proceeds of the Borrowings.
(c)To the fullest extent permitted by applicable law, the Borrower agrees not to assert, or permit any of their Affiliates or Related Parties to assert, and each hereby waives, any claim against any Indemnified Party on any theory of liability, for consequential damages (including lost profits) arising out of or otherwise relating to this Agreement, any of the transactions contemplated herein or the actual or proposed use of the proceeds of the Borrowings.
(d)If any payment of principal of, or Conversion of, any Eurodollar Rate Advance is made by the Borrower to or for the account of a Lender other than on the last day of the Interest Period for such Advance, as a result of a payment or Conversion pursuant to Section 2.05, 2.08(e), 2.09, 2.10 or 2.12, acceleration of the maturity of the outstanding Borrowings pursuant to Section 6.01, the assignment of any such Advance pursuant to Section 2.15(b) or for any other reason (in the case of any such payment or Conversion), the Borrower shall, promptly upon demand by such Lender (with a copy of such demand to the Administrative Agent), pay to the Administrative Agent for the account of such Lender any amounts required to compensate such Lender for any additional losses, costs or expenses that it may reasonably incur as a result of such

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payment or Conversion, including, without limitation, any loss (other than loss of Applicable Margin), cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by any Lender to fund or maintain such Advance.
(e)Without prejudice to the survival of any other agreement of the Borrower hereunder, the agreements and obligations of the Borrower contained in Sections 2.11, 2.14 and 8.04 shall survive the payment in full of principal, interest and all other amounts payable hereunder.
(f)The Borrower agrees that no Indemnified Party shall have any liability (whether direct or indirect, in contract or tort or otherwise) to the Borrower or its security holders or creditors related to or arising out of or in connection with this Agreement, the Borrowings or the use or proposed use of the proceeds thereof, any of the transactions contemplated by any of the foregoing or in the loan documentation or the performance by an Indemnified Party of any of the foregoing (including the use by unintended recipients of any information or other materials distributed through telecommunications, electronic or other information transmission systems in connection with this Agreement or the other Loan Documents) except to the extent that any loss, claim, damage, liability or expense is found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from such Indemnified Party’s gross negligence or willful misconduct.
(g)In the event that an Indemnified Party is requested or required to appear as a witness in any action brought by or on behalf of or against the Borrower or any of its Affiliates in which such Indemnified Party is not named as a defendant, the Borrower agrees to reimburse such Indemnified Party for all reasonable expenses incurred by it in connection with such Indemnified Party’s appearing and preparing to appear as such a witness, including, without limitation, the fees and disbursements of its legal counsel.
SECTION 8.05    Right of Set-off.
Upon (i) the occurrence and during the continuance of any Event of Default and (ii) the making of the request or the granting of the consent specified by Section 6.01 to authorize the Administrative Agent to declare the outstanding Borrowings due and payable pursuant to the provisions of Section 6.01, each Recipient and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by such Recipient or such Affiliate to or for the credit or the account of the Borrower against any and all of the obligations of the Borrower now or hereafter existing under this Agreement held by such Recipient, whether or not such Recipient shall have made any demand under this Agreement and although such obligations may be unmatured; provided that, in the event that any Defaulting Lender shall exercise any such right of setoff, (x) all amounts so set off shall be paid over immediately to the Administrative Agent for further application in accordance with the provisions of Section 8.16 and, pending such payment, shall be segregated by such Defaulting Lender from its other funds and deemed held in trust for the benefit of the Administrative Agent and the Lenders, and (y) the Defaulting Lender shall provide promptly to the Administrative Agent a statement describing in reasonable detail the obligations of the Borrower owing to such Defaulting Lender as to which it exercised such right of setoff. Each

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Recipient agrees promptly to notify the Borrower after any such set-off and application, provided that the failure to give such notice shall not affect the validity of such set-off and application. The rights of each Recipient and its Affiliates under this Section are in addition to other rights and remedies (including, without limitation, other rights of set-off) that such Recipient and its Affiliates may have.
SECTION 8.06    Binding Effect.
This Agreement shall become effective upon satisfaction of the conditions precedent specified in Section 3.01 and thereafter shall be binding upon and inure to the benefit of the Borrower, the Administrative Agent and each Lender and their respective successors and assigns, except that the Borrower shall not have the right to assign its rights hereunder or any interest herein without the prior written consent of all of the Lenders. Neither the Arrangers nor any Person designated as a “Documentation Agent” or a “Syndication Agent” with respect to this Agreement shall have any duties under this Agreement.
SECTION 8.07    Assignments and Participations.
(a)Successors and Assigns of Lenders Generally. No Lender may assign or otherwise transfer any of its rights or obligations hereunder except (i) to an assignee in accordance with the provisions of subsection (b) of this Section, (ii) by way of participation in accordance with the provisions of subsection (d) of this Section, or (iii) by way of pledge or assignment of a security interest subject to the restrictions of subsection (e) of this Section (and any other attempted assignment or transfer by any party hereto shall be null and void). Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby, Participants to the extent provided in subsection (d) of this Section and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.
(b)Assignments by Lenders. Any Lender may at any time assign to one or more assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Advances at the time owing to it); provided that any such assignment shall be subject to the following conditions:
(i)Minimum Amounts.
(A)in the case of an assignment of the entire remaining amount of the assigning Lender’s Commitment and/or the Advances at the time owing to it or contemporaneous assignments to related Approved Funds that equal at least the amount specified in subsection (b)(i)(B) of this Section in the aggregate or in the case of an assignment to a Lender, an Affiliate of a Lender or an Approved Fund, no minimum amount need be assigned; and
(B)in any case not described in subsection (b)(i)(A) of this Section, the aggregate amount of the Commitment and/or Advances of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the

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Administrative Agent or, if the “Trade Date” is specified in the Assignment and Assumption, as of the Trade Date) shall not be less than $5,000,000 or an integral multiple of $1,000,000 in excess thereof, unless each of the Administrative Agent and, so long as no Default has occurred and is continuing, the Borrower otherwise consents (each such consent not to be unreasonably withheld or delayed).
(ii)Proportionate Amounts. Each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement with respect to the Advances or the Commitment of such Lender being assigned.
(iii)Required Consents. No consent shall be required for any assignment except to the extent required by subsection (b)(i)(B) of this Section and, in addition:

(A)the consent of the Borrower (such consent not to be unreasonably withheld or delayed) shall be required unless (x) a Default has occurred and is continuing at the time of such assignment, or (y) such assignment is to a Lender, an Affiliate of a Lender or an Approved Fund; provided that the Borrower shall be deemed to have consented to any such assignment unless it shall object thereto by written notice to the Administrative Agent within 10 Business Days after having received notice thereof; and
(B)the consent of the Administrative Agent (such consent not to be unreasonably withheld or delayed) shall be required for assignments in respect of (i) any unfunded Commitments if such assignment is to a Person that is not a Lender with a Commitment, an Affiliate of such Lender or an Approved Fund with respect to such Lender, or (ii) any Advance to a Person that is not a Lender, an Affiliate of a Lender or an Approved Fund,
(iv)Assignment and Assumption. The parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500 (to be paid by the assigning Lender, or, in the case of an assignment pursuant to Section 2.15(b), the Borrower); provided that the Administrative Agent may, in its sole discretion, elect to waive such processing and recordation fee in the case of any assignment. The assignee, if it is not a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire.
(v)No Assignment to Certain Persons. No such assignment shall be made to (A) the Borrower or any of the Borrower’s Affiliates or Subsidiaries or (B) to any Defaulting Lender or any of its Subsidiaries, or any Person that, upon becoming a Lender hereunder, would constitute any of the foregoing Persons described in this clause (B).
(vi)No Assignment to Natural Persons. No such assignment shall be made to a natural Person (or a holding company, investment vehicle or trust for, or owned and operated for the primary benefit of, a natural Person).

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(vii)Certain Additional Payments. In connection with any assignment of rights and obligations of any Defaulting Lender hereunder, no such assignment shall be effective unless and until, in addition to the other conditions thereto set forth herein, the parties to the assignment shall make such additional payments to the Administrative Agent in an aggregate amount sufficient, upon distribution thereof as appropriate (which may be outright payment, purchases by the assignee of participations or subparticipations, or other compensating actions, including funding, with the consent of the Borrower and the Administrative Agent, the applicable pro rata share of Advances previously requested but not funded by the Defaulting Lender, to each of which the applicable assignee and assignor hereby irrevocably consent), to (x) pay and satisfy in full all payment liabilities then owed by such Defaulting Lender to the Administrative Agent and each Lender hereunder (and interest accrued thereon), and (y) acquire (and fund as appropriate) its full pro rata share of all Advances and Commitments in accordance with its Commitment Percentage. Notwithstanding the foregoing, in the event that any assignment of rights and obligations of any Defaulting Lender hereunder shall become effective under Applicable Law without compliance with the provisions of this subsection, then the assignee of such interest shall be deemed to be a Defaulting Lender for all purposes of this Agreement until such compliance occurs.
(viii)
Subject to acceptance and recording thereof by the Administrative Agent pursuant to subsection (c) of this Section, from and after the effective date specified in each Assignment and Assumption, the assignee thereunder shall be a party to this Agreement and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto) but shall continue to be entitled to the benefits of Sections 2.11, 2.14 and 8.04 with respect to facts and circumstances occurring prior to the effective date of such assignment; provided, that except to the extent otherwise expressly agreed in writing by the affected parties, no assignment by a Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this subsection shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with subsection (d) of this Section.
(c)Register. The Administrative Agent, acting solely for this purpose as a non-fiduciary agent of the Borrower, shall maintain at its address referred to in Section 8.02 a copy of each Assignment and Assumption delivered to it and a register in which it shall record the names and addresses of the Lenders, and the Commitments of, and principal amounts (and stated interest) of the Advances owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive absent manifest error, and the Borrower, the Administrative Agent and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

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(d)Participations. Any Lender may at any time, without the consent of, or notice to, the Borrower or the Administrative Agent, sell participations to any Person (other than a natural Person or a holding company, investment vehicle or trust for, or owned and operated for the primary benefit of, a natural Person, or the Borrower or any of the Borrower’s Affiliates or Subsidiaries) (each, a “Participant”) in all or a portion of such Lender’s rights and/or obligations under this Agreement (including all or a portion of its Commitment and/or the Advances owing to it); provided that (i) such Lender’s obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, and (iii) the Borrower, the Administrative Agent and Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. For the avoidance of doubt, each Lender shall be responsible for the indemnity obligations under Section 7.06 with respect to any payments made by such Lender to its Participant(s).
Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver with respect to clauses (i) through (vi) of Section 8.01 that affects such participant. The Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.02(c), 2.11, 2.14, 8.04(b), 8.04(c) and 8.04(d) (subject to the requirements and limitations therein, including the requirements under Section 2.14(f) (it being understood that the documentation required under Section 2.14(f) shall be delivered to the participating Lender)) to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to subsection (b) of this Section; provided that such Participant (A) agrees to be subject to the provisions of Section 2.15(b) as if it were an assignee under subsection (b) of this Section; and (B) shall not be entitled to receive any greater payment under Sections 2.11 or 2.14, with respect to any participation, than its participating Lender would have been entitled to receive, except to the extent such entitlement to receive a greater payment results from a Change in Law that occurs after the Participant acquired the applicable participation. Each Lender that sells a participation agrees, at the Borrower's request and expense, to use reasonable efforts to cooperate with the Borrower to effectuate the provisions of Section 2.15(b) with respect to any Participant. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 8.05 as though it were a Lender; provided that such Participant agrees to be subject to Section 2.16 as though it were a Lender. Each Lender that sells a participation shall, acting solely for this purpose as a non-fiduciary agent of the Borrower, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Advances or other obligations under the Loan Documents (the “Participant Register”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register (including the identity of any Participant or any information relating to a Participant's interest in any Commitments, Advances or its other obligations under any Loan Document) to any Person except to the extent that such disclosure is necessary to establish that such Commitment, Advance or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. For the avoidance of doubt, the Administrative Agent

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(in its capacity as Administrative Agent) shall have no responsibility for maintaining a Participant Register.
(e)Certain Pledges. Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or any other central banking authority; provided that no such pledge or assignment shall release such Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.
SECTION 8.08    Confidentiality.
Each of the Administrative Agent and the Lenders agree to maintain the confidentiality of the Confidential Information, except that Confidential Information may be disclosed (a) to its Affiliates and to its Related Parties (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Confidential Information and instructed to keep such Confidential Information confidential); (b) to the extent required or requested by any regulatory authority purporting to have jurisdiction over such Person or its Related Parties (including any state, federal or foreign authority or examiner regulating banks, banking or other financial institutions and any self-regulatory authority, such as the National Association of Insurance Commissioners); (c) to the extent required by Applicable Law or by any subpoena or similar legal process; (d) to any other party hereto; (e) in connection with the exercise of any remedies hereunder or under any other Loan Document or any action or proceeding relating to this Agreement or any other Loan Document or the enforcement of rights hereunder or thereunder; (f) subject to an agreement containing provisions substantially the same as those of this Section, to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights and obligations under this Agreement, (ii) any actual or prospective party (or its Related Parties) to any swap, derivative or other transaction under which payments are to be made by reference to the Borrower and its obligations, this Agreement or payments hereunder or (iii) any credit insurance provider relating to the Borrower and its obligations; (g) on a confidential basis to (i) any rating agency in connection with rating the Borrower or its Subsidiaries or this Agreement or (ii) the CUSIP Service Bureau or any similar agency in connection with the issuance and monitoring of CUSIP numbers with respect to this Agreement; (h) with the consent of the Borrower; or (i) to the extent such Confidential Information (x) becomes publicly available other than as a result of a breach of this Section, or (y) becomes available to the Administrative Agent, any Lender or any of their respective Affiliates on a nonconfidential basis from a source other than the Borrower. In addition, the Administrative Agent and each Lender may disclose the existence of this Agreement and information about this Agreement to market data collectors, similar service providers to the lending industry and service providers to the Administrative Agent or any Lender in connection with the administration or servicing of this Agreement, the other Loan Documents and the Commitments. Any Person required to maintain the confidentiality of Confidential Information as provided in this Section shall be considered to have complied with its obligation to do so if such Person has exercised the same degree of care to maintain the confidentiality of such Confidential Information as such Person would accord to its own confidential information.
SECTION 8.09    Governing Law.

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THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.
SECTION 8.10    Severability; Survival; Entire Agreement.
(a)In the event any one or more of the provisions contained in this Agreement should be held invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not in any way be affected or impaired hereby.
(b)All covenants, agreements, representations and warranties made by the Borrower herein and in the certificates or other instruments delivered in connection with or pursuant to this Agreement shall be considered to have been relied upon by the other parties hereto and shall survive the execution and delivery of this Agreement and the making of any Advances, regardless of any investigation made by any such other party or on its behalf and notwithstanding that the Administrative Agent or any Lender may have had notice or knowledge of any Default or incorrect representation or warranty at the time any credit is extended hereunder, and shall continue in full force and effect as long as the principal of or any accrued interest on any Advance or any fee or any other amount payable under this Agreement is outstanding and unpaid and so long as the Commitments have not expired or terminated.
(c)The Loan Documents constitute the entire contract among the parties relative to the subject matter hereof. Any previous agreement, written or oral, among the parties with respect to the subject matter hereof is superseded by this Agreement, except (i) as expressly stated in any other Loan Document and (ii) for the Fee Letter.
SECTION 8.11    Execution in Counterparts.
This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Agreement and the other Loan Documents by fax or other electronic imaging shall be effective as delivery of a manually executed counterpart of this Agreement and the other Loan Documents, as the case may be, to the extent and as provided for in any Applicable Law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act.
SECTION 8.12    Jurisdiction, Etc.
(a)EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY AND UNCONDITIONALLY SUBMITS, FOR ITSELF AND ITS PROPERTY, TO THE EXCLUSIVE JURISDICTION OF ANY NEW YORK STATE COURT OR FEDERAL COURT OF THE UNITED STATES OF AMERICA SITTING IN NEW YORK CITY, THE COUNTY OF NEW YORK, AND ANY APPELLATE COURT FROM ANY THEREOF, IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, OR FOR RECOGNITION OR ENFORCEMENT OF ANY JUDGMENT, AND EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY AND UNCONDITIONALLY AGREES THAT ALL

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CLAIMS IN RESPECT OF ANY SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN ANY SUCH NEW YORK STATE COURT OR, TO THE EXTENT PERMITTED BY LAW, IN SUCH FEDERAL COURT. EACH OF THE PARTIES HERETO AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW. NOTHING IN THIS AGREEMENT SHALL AFFECT ANY RIGHT THAT ANY PARTY MAY OTHERWISE HAVE TO BRING ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT IN THE COURTS OF ANY JURISDICTION.
(b)EACH OF THE PARTIES HERETO IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT IT MAY LEGALLY AND EFFECTIVELY DO SO, ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT IN ANY NEW YORK STATE OR FEDERAL COURT. EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF SUCH ACTION OR PROCEEDING IN ANY SUCH COURT.
(c)BORROWER HEREBY WAIVES PERSONAL SERVICE OF ANY AND ALL PROCESS AND AGREES THAT ALL SUCH SERVICE OF PROCESS MAY BE MADE UPON BORROWER BY CERTIFIED OR REGISTERED MAIL, RETURN RECEIPT REQUESTED, ADDRESSED TO BORROWER AT THE ADDRESS SET FORTH IN THIS AGREEMENT AND SERVICE SO MADE SHALL BE COMPLETE TEN (10) DAYS AFTER THE SAME HAS BEEN POSTED.
SECTION 8.13    Waiver of Jury Trial.
EACH PARTY HERETO HEREBY IRREVOCABLY WAIVES ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THE LOAN DOCUMENTS OR THE TRANSACTIONS CONTEMPLATED THEREBY AND AGREES THAT ANY SUCH ACTION OR PROCEEDING SHALL BE TRIED BEFORE A COURT AND NOT BEFORE A JURY. EACH PARTY HERETO ACKNOWLEDGES THAT THIS WAIVER IS A MATERIAL INDUCEMENT TO ENTER INTO A BUSINESS RELATIONSHIP, THAT EACH HAS RELIED ON THE WAIVER IN ENTERING INTO THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS, AND THAT EACH WILL CONTINUE TO RELY ON THIS WAIVER IN THEIR RELATED FUTURE DEALINGS. EACH PARTY HERETO WARRANTS AND REPRESENTS THAT EACH HAS HAD THE OPPORTUNITY OF REVIEWING THIS JURY WAIVER WITH LEGAL COUNSEL, AND THAT EACH KNOWINGLY AND VOLUNTARILY WAIVES ITS JURY TRIAL RIGHTS.
SECTION 8.14    USA Patriot Act.
Each of the Lenders and the Administrative Agent (for itself and not on behalf of any Lender) hereby notifies the Borrower that (a) pursuant to the requirements of the USA Patriot Act

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(Title III of Pub. L. 107-56 (signed into law as of October 26, 2001)) (as amended, restated, modified or otherwise supplemented from time to time, the “Patriot Act”), it is required to obtain, verify and record information that identifies the Borrower, which information includes the name and address of the Borrower and other information that will allow such Lender or the Administrative Agent, as applicable, to identify the Borrower in accordance with the Patriot Act and (b) pursuant to the Beneficial Ownership Regulation, it is required to obtain a Beneficial Ownership Certificate. The Borrower shall, and shall cause each of its subsidiaries to, provide to the extent commercially reasonable, such information and take such actions as are reasonably requested by the Administrative Agent or any Lender in order to assist the Administrative Agent and the Lenders in maintaining compliance with the Patriot Act.
SECTION 8.15    No Fiduciary Duty.
The Administrative Agent, the Arrangers, each Lender and each of their respective Affiliates and each of their respective officers, directors, controlling persons, employees, agents and advisors (collectively, solely for purposes of this Section 8.15, the “Lenders”) may be engaged, for their own accounts or the accounts of customers, in a broad range of transactions that involve interests that differ from those the Borrower and its Affiliates, and none of the Lenders has any obligation to disclose any of such interests to the Borrower or any of its Affiliates. The Borrower agrees that nothing in the Loan Documents or otherwise will be deemed to create an advisory, fiduciary or agency relationship or fiduciary or other implied duty between the Lenders and the Borrower, its stockholders or its Affiliates. The Borrower acknowledges and agrees that (i) the transactions contemplated by the Loan Documents are arm’s-length commercial transactions between the Lenders, on the one hand, and the Borrower, on the other, (ii) in connection therewith and with the process leading to such transaction each of the Lenders is acting solely as a principal and not the agent or fiduciary of the Borrower, its management, stockholders, creditors or any other person, (iii) no Lender has assumed an advisory or fiduciary responsibility in favor of the Borrower with respect to the transactions contemplated hereby or the process leading thereto (irrespective of whether any Lender or any of its Affiliates has advised or is currently advising the Borrower on other matters) or any other obligation to the Borrower except the obligations expressly set forth in the Loan Documents and (iv) the Borrower has consulted its own legal and financial advisors to the extent it deemed appropriate. The Borrower further acknowledges and agrees that it is responsible for making its own independent judgment with respect to such transactions and the process leading thereto. The Borrower agrees that it will not claim, and hereby waives and releases any claim to the fullest extent permitted by law, that any Lender (x) has rendered advisory services of any nature or respect, (y) has committed a breach of agency, fiduciary or similar duty, or (z) owes a duty of agency, fiduciary or similar duty to the Borrower, in each case in connection with such transaction or the process leading thereto.
SECTION 8.15    Defaulting Lenders.
(a)Defaulting Lender Adjustments.     Notwithstanding anything to the contrary contained in this Agreement, if any Lender becomes a Defaulting Lender, then, until such time as such Lender is no longer a Defaulting Lender, to the extent permitted by Applicable Law:

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(i)Waivers and Amendments. Such Defaulting Lender’s right to approve or disapprove any amendment, waiver or consent with respect to this Agreement shall be restricted as set forth in the definition of Required Lenders and in Section 8.01.
(ii)Defaulting Lender Waterfall. Any payment of principal, interest, fees or other amounts received by the Administrative Agent for the account of such Defaulting Lender (whether voluntary or mandatory, at maturity, pursuant to Article VI or otherwise) or received by the Administrative Agent from a Defaulting Lender pursuant to Section 8.05 shall be applied at such time or times as may be determined by the Administrative Agent as follows: first, to the payment of any amounts owing by such Defaulting Lender to the Administrative Agent hereunder; second, as the Borrower may request (so long as no Default exists), to the funding of any Advance in respect of which such Defaulting Lender has failed to fund its portion thereof as required by this Agreement, as determined by the Administrative Agent; third, if so determined by the Administrative Agent and the Borrower, to be held in a deposit account and released pro rata in order to satisfy such Defaulting Lender’s potential future funding obligations with respect to Advances under this Agreement; fourth, to the payment of any amounts owing to the Lenders as a result of any judgment of a court of competent jurisdiction obtained by any Lender against such Defaulting Lender as a result of such Defaulting Lender’s breach of its obligations under this Agreement; fifth, so long as no Default exists, to the payment of any amounts owing to the Borrower as a result of any judgment of a court of competent jurisdiction obtained by the Borrower against such Defaulting Lender as a result of such Defaulting Lender's breach of its obligations under this Agreement; and sixth, to such Defaulting Lender or as otherwise directed by a court of competent jurisdiction; provided that, if (x) such payment is a payment of the principal amount of any Advances in respect of which such Defaulting Lender has not fully funded its appropriate share, and (y) such Advances were made at a time when the conditions set forth in Section 3.02 were satisfied or waived, such payment shall be applied solely to pay the Advances of all Non-Defaulting Lenders on a pro rata basis prior to being applied to the payment of any Advances of such Defaulting Lender until such time as all Advances are held by the Lenders pro rata in accordance with the Commitments. Any payments, prepayments or other amounts paid or payable to a Defaulting Lender that are applied (or held) to pay amounts owed by a Defaulting Lender pursuant to this Section 8.16(a)(ii) shall be deemed paid to and redirected by such Defaulting Lender, and each Lender irrevocably consents hereto.

(iii)Certain Fees. No Defaulting Lender shall be entitled to receive any commitment fee pursuant to Section 2.03(a) for any period during which that Lender is a Defaulting Lender (and the Borrower shall not be required to pay any such fee that otherwise would have been required to have been paid to that Defaulting Lender).

(iv)Reduction of Commitments. The Borrower may terminate the Commitment of any Lender that is a Defaulting Lender upon not less than three Business Days’ prior notice to the Administrative Agent (which shall promptly notify the Lenders thereof), and in such event the provisions of Section 8.16(a)(ii) will apply to all amounts thereafter paid by the Borrower for the account of such Defaulting Lender under this Agreement (whether on account of principal, interest, fees, indemnity or other amounts); provided that (i) no Event of Default shall have occurred and be continuing and (ii) such

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termination shall not be deemed to be a waiver or release of any claim the Borrower, the Administrative Agent or any Lender may have against such Defaulting Lender.

(b)Defaulting Lender Cure. If the Borrower and the Administrative Agent agree in writing that a Lender is no longer a Defaulting Lender, the Administrative Agent will so notify the parties hereto, whereupon as of the effective date specified in such notice and subject to any conditions set forth therein, that Lender will, to the extent applicable, purchase at par that portion of outstanding Advances of the other Lenders or take such other actions as the Administrative Agent may determine to be necessary to cause the Advances to be held pro rata by the Lenders in accordance with the Commitments, whereupon such Lender will cease to be a Defaulting Lender; provided that no adjustments will be made retroactively with respect to fees accrued or payments made by or on behalf of the Borrower while that Lender was a Defaulting Lender; and provided, further, that except to the extent otherwise expressly agreed in writing by the affected parties, no change hereunder from Defaulting Lender to Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender.
SECTION 8.17    Acknowledgement and Consent to Bail-In of Affected Financial Institutions.
Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Lender that is an Affected Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the write-down and conversion powers of the applicable Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:
(a)the application of any Write-Down and Conversion Powers by the applicable Resolution Authority to any such liabilities arising hereunder which may be payable to it by any Lender that is an Affected Financial Institution; and
(b)the effects of any Bail-in Action on any such liability, including, if applicable:
(i)a reduction in full or in part or cancellation of any such liability;
(ii)a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such Affected Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

(iii)the variation of the terms of such liability in connection with the exercise of the Write-Down and Conversion Powers of the applicable Resolution Authority.

SECTION 8.18    Interest Rate Limitation.

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Notwithstanding anything herein to the contrary, if at any time the interest rate applicable to any Advance, together with all fees, charges and other amounts which are treated as interest on such Advance under applicable law (collectively, the “Charges”), shall exceed the maximum lawful rate (the “Maximum Rate”) which may be contracted for, charged, taken, received or reserved by the Lender making such Advance in accordance with applicable law, the rate of interest payable in respect of such Advance hereunder, together with all Charges payable in respect thereof, shall be limited to the Maximum Rate and, to the extent lawful, the interest and charges that would have been payable in respect of such Advance but were not payable as a result of the operation of this Section 8.18 shall be cumulated and the interest and charges payable to such Lender in respect of other Advances or periods shall be increased (but not above the Maximum Rate therefor) until such cumulated amount, together with interest thereon at the Applicable Margin to the date of repayment, shall have been received by such Lender.
SECTION 8.19    Certain ERISA Matters.
(a)Each Lender (x) represents and warrants, as of the date such person became a Lender party hereto, to, and (y) covenants, from the date such person became a Lender party hereto to the date such person ceases being a Lender party hereto, for the benefit of, the Administrative Agent and the Arrangers and their respective Affiliates, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that at least one of the following is and will be true:
(i)such Lender is not using “plan assets” (within the meaning of Section 3(42) of ERISA or otherwise) of one or more Benefit Plans with respect to such Lender’s entrance into, participation in, administration of and performance of the Advances, the Commitments or this Agreement,
(ii)the transaction exemption set forth in one or more PTEs, such as PTE 84-14 (a class exemption for certain transactions determined by independent qualified professional asset managers), PTE 95-60 (a class exemption for certain transactions involving insurance company general accounts), PTE 90-1 (a class exemption for certain transactions involving insurance company pooled separate accounts), PTE 91-38 (a class exemption for certain transactions involving bank collective investment funds) or PTE 96-23 (a class exemption for certain transactions determined by in-house asset managers), is applicable with respect to such Lender’s entrance into, participation in, administration of and performance of the Advances, the Commitments and this Agreement,

(iii)(A) such Lender is an investment fund managed by a “Qualified Professional Asset Manager” (within the meaning of Part VI of PTE 84-14), (B) such Qualified Professional Asset Manager made the investment decision on behalf of such Lender to enter into, participate in, administer and perform the Advances, the Commitments and this Agreement, (C) the entrance into, participation in, administration of and performance of the Advances,

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the Commitments and this Agreement satisfies the requirements of sub-sections (b) through (g) of Part I of PTE 84-14 and (D) to the best knowledge of such Lender, the requirements of subsection (a) of Part I of PTE 84-14 are satisfied with respect to such Lender’s entrance into, participation in, administration of and performance of the Advances, the Commitments and this Agreement, or

(iv)such other representation, warranty and covenant as may be agreed in writing between the Administrative Agent, in its sole discretion, and such Lender.

(b)In addition, unless either (1) sub-clause (i) in the immediately preceding clause (a) is true with respect to a Lender or (2) Lender has provided another representation, warranty and covenant in accordance with sub-clause (iv) in the immediately preceding clause (a), such Lender further (x) represents and warrants, as of the date such person became a Lender party hereto, to, and (y) covenants, from the date such person became a Lender party hereto to the date such person ceases being a Lender party hereto, for the benefit of, the Administrative Agent and the Arrangers and their respective Affiliates, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that none of the Administrative Agent, the Arrangers or any of their respective Affiliates is a fiduciary with respect to the assets of such Lender involved in such Lender’s entrance into, participation in, administration of and performance of the Advances, the Commitments and this Agreement (including in connection with the reservation or exercise of any rights by the Administrative Agent under this Agreement, any Loan Document or any documents related hereto or thereto).
SECTION 8.20    Eurodollar Rate Notification.
Section 8.21 of this Agreement provides a mechanism for determining an alternative rate of interest in the event that the London interbank offered rate is no longer available or in certain other circumstances. The Administrative Agent does not warrant or accept any responsibility for and shall not have any liability with respect to, the administration, submission or any other matter related to the London interbank offered rate or other rates in the definition of “Eurodollar Rate” or with respect to any alternative or successor rate thereto, or replacement rate therefor.
SECTION 8.21    Successor Eurodollar Rate Index
(a)Benchmark Replacement. Notwithstanding anything to the contrary herein or in any other Loan Document, if the Administrative Agent determines that a Benchmark Transition Event or an Early Opt-in Event has occurred, the Administrative Agent and the Borrower may amend this Agreement to replace the Eurodollar Rate with a Benchmark Replacement; and any such amendment will become effective at 5:00 p.m. New York City time on the fifth (5th) Business Day after the Administrative Agent has provided such proposed amendment to all Lenders, so long as the Administrative Agent has not received, by such time, written notice of objection to such amendment from Lenders comprising the Required Lenders. Until the Benchmark Replacement is effective, each making, conversion and renewal of an Advance under the Eurodollar Rate option will continue to bear interest with reference to the Eurodollar Rate; provided however, during a Benchmark Unavailability Period (i) any pending

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selection of, conversion to or renewal of an Advance bearing interest under the Eurodollar Rate option that has not yet gone into effect shall be deemed to be a selection of, conversion to or renewal of the Base Rate option with respect to such Advance, (ii) all outstanding Advances bearing interest under the Eurodollar Rate option shall automatically be converted to the Base Rate option at the expiration of the existing Interest Period (or sooner, if Administrative Agent cannot continue to lawfully maintain such affected Advance under the Eurodollar Rate option) and (iii) the component of the Base Rate based upon the Eurodollar Rate will not be used in any determination of the Base Rate.
(b)Benchmark Replacement Conforming Changes. In connection with the implementation of a Benchmark Replacement, the Administrative Agent will have the right to make Benchmark Replacement Conforming Changes from time to time and, notwithstanding anything to the contrary herein or in any other Loan Document, any amendments implementing such Benchmark Replacement Conforming Changes will become effective without any further action or consent of any other party to this Agreement.
(c)Notices; Standards for Decisions and Determinations. The Administrative Agent will promptly notify the Borrower and the Lenders of (i) the implementation of any Benchmark Replacement, (ii) the effectiveness of any Benchmark Replacement Conforming Changes and (iii) the commencement of any Benchmark Unavailability Period. Any determination, decision or election that may be made by the Administrative Agent or the Lenders pursuant to this Section 8.21 including any determination with respect to a tenor, rate or adjustment or of the occurrence or non-occurrence of an event, circumstance or date and any decision to take or refrain from taking any action, will be conclusive and binding absent manifest error and may be made in its or their sole discretion and without consent from any other party hereto, except, in each case, as expressly required pursuant to this Section 8.21.
(d)Certain Defined Terms. As used in this Section 8.21:
“Benchmark Replacement” means the sum of: (a) the alternate benchmark rate that has been selected by the Administrative Agent and the Borrower giving due consideration to (i) any selection or recommendation of a replacement rate or the mechanism for determining such a rate by the Relevant Governmental Body or (ii) any evolving or then-prevailing market convention for determining a rate of interest as a replacement to the Eurodollar Rate for U.S. dollar-denominated syndicated credit facilities and (b) the Benchmark Replacement Adjustment; provided that, if the Benchmark Replacement as so determined would be less than zero, the Benchmark Replacement will be deemed to be zero for the purposes of this Agreement.
“Benchmark Replacement Adjustment” means, with respect to any replacement of the Eurodollar Rate with an alternate benchmark rate for each applicable Interest Period, the spread adjustment, or method for calculating or determining such spread adjustment, (which may be a positive or negative value or zero) that has been selected by the Administrative Agent and the Borrower (a) giving due consideration to (i) any selection or recommendation of a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of the Eurodollar Rate with the applicable Benchmark Replacement (excluding such spread adjustment) by the Relevant Governmental Body or (ii) any evolving or then-prevailing market convention for determining a spread adjustment, or method for calculating or determining such

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spread adjustment, for such replacement of the Eurodollar Rate for U.S. dollar-denominated syndicated credit facilities at such time and (b) which may also reflect adjustments to account for (i) the effects of the transition from the Eurodollar Rate to the Benchmark Replacement and (ii) yield- or risk-based differences between the Eurodollar Rate and the Benchmark Replacement.
“Benchmark Replacement Conforming Changes” means, with respect to any Benchmark Replacement, any technical, administrative or operational changes (including changes to the definition of “Base Rate,” the definition of “Interest Period,” timing and frequency of determining rates and making payments of interest and other administrative matters) that the Administrative Agent decides may be appropriate to reflect the adoption and implementation of such Benchmark Replacement and to permit the administration thereof by the Administrative Agent in a manner substantially consistent with market practice (or, if the Administrative Agent decides that adoption of any portion of such market practice is not administratively feasible or if the Administrative Agent determines that no market practice for the administration of the Benchmark Replacement exists, in such other manner of administration as the Administrative Agent decides is reasonably necessary in connection with the administration of this Agreement).
“Benchmark Replacement Date” means the earlier to occur of the following events with respect to the Eurodollar Rate:
(1)    in the case of clause (1) or (2) of the definition of “Benchmark Transition Event,” the later of (a) the date of the public statement or publication of information referenced therein and (b) the date on which the administrator of the Eurodollar Rate permanently or indefinitely ceases to provide the Eurodollar Rate; or
(2)     in the case of clause (3) of the definition of “Benchmark Transition Event,” the date of the public statement or publication of information referenced therein.
“Benchmark Transition Event” means the occurrence of one or more of the following events with respect to the Eurodollar Rate:
(1)     a public statement or publication of information by or on behalf of the administrator of the Eurodollar Rate announcing that such administrator has ceased or will cease to provide the Eurodollar Rate, permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide the Eurodollar Rate;
(2)     a public statement or publication of information by a Governmental Authority having jurisdiction over the Administrative Agent, the regulatory supervisor for the administrator of the Eurodollar Rate, the U.S. Federal Reserve System, an insolvency official with jurisdiction over the administrator for the Eurodollar Rate, a resolution authority with jurisdiction over the administrator for the Eurodollar Rate or a court or an entity with similar insolvency or resolution authority over the administrator for the Eurodollar Rate, which states that the administrator of the Eurodollar Rate has ceased or will cease to provide the Eurodollar Rate permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide the Eurodollar Rate; or

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(3)     a public statement or publication of information by the regulatory supervisor for the administrator of the Eurodollar Rate or a Governmental Authority having jurisdiction over the Administrative Agent announcing that the Eurodollar Rate is no longer representative.
“Benchmark Unavailability Period” means, if a Benchmark Transition Event and its related Benchmark Replacement Date have occurred with respect to the Eurodollar Rate and solely to the extent that the Eurodollar Rate has not been replaced with a Benchmark Replacement, the period (x) beginning at the time that such Benchmark Replacement Date has occurred if, at such time, no Benchmark Replacement has replaced the Eurodollar Rate for all purposes hereunder in accordance with Section 8.21 and (y) ending at the time that a Benchmark Replacement has replaced the Eurodollar Rate for all purposes hereunder pursuant to Section 8.21.
“Early Opt-in Event” means (i) a determination by the Administrative Agent or (ii) a notification by the Required Lenders to the Administrative Agent (with a copy to the Borrower) that the Required Lenders have determined that U.S. dollar-denominated syndicated credit facilities being executed at such time, or that include language similar to that contained in this Section 8.21, are being executed or amended, as applicable, to incorporate or adopt a new benchmark interest rate to replace the Eurodollar Rate.
“Relevant Governmental Body” means the Federal Reserve Board and/or the Federal Reserve Bank of New York, or a committee officially endorsed or convened by the Federal Reserve Board and/or the Federal Reserve Bank of New York or any successor thereto.

[Remainder of page intentionally left blank.]

IN WITNESS WHEREOF, each party hereto has caused a counterpart of this Agreement to be duly executed and delivered as of the date first above written.

PUBLIC SERVICE COMPANY OF
OKLAHOMA, as the Borrower

By    /s/Renee V. Hawkins    
Name: Renee V. Hawkins
Title: Assistant Treasurer

PUBLIC SERVICE COMPANY OF OKLAHOMA – CREDIT AGREEMENT

SUMITOMO MITSUI BANKING
CORPORATION, as Administrative Agent and as
Lender

By    /s/Katie Lee    
Name: Katie Lee
Title: Director

PUBLIC SERVICE COMPANY OF OKLAHOMA – CREDIT AGREEMENT

WELLS FARGO BANK, NATIONAL
ASSOCIATION, as Lender

By    /s/ Keith Luettel    
Name: Keith Luettel
Title: Managing Director

PUBLIC SERVICE COMPANY OF OKLAHOMA – CREDIT AGREEMENT

PNC BANK, NATIONAL ASSOCIATION, as
Lender

By    /s/ Kelly Sarver    
Name: Kelly Sarver
Title: Vice President

PUBLIC SERVICE COMPANY OF OKLAHOMA – CREDIT AGREEMENT

KEYBANK NATIONAL ASSOCIATION, as
Lender

By    /s/ Renee M. Bonnell    
Name: Renee M. Bonnell
Title: Senior Vice President

PUBLIC SERVICE COMPANY OF OKLAHOMA – CREDIT AGREEMENT

CREDIT AGRICOLE CORPORATE AND
INVESTMENT BANK, as Lender

By    /s/ Darrell Stanley    
Name: Darrell Stanley
Title: Managing Director

By    /s/ Nimisha Srivastav    
Name: Nimisha Srivastav
Title: Director

PUBLIC SERVICE COMPANY OF OKLAHOMA – CREDIT AGREEMENT

Schedule I

Schedule of Initial Lenders

Lender Name	Commitment	
Sumitomo Mitsui Banking Corporation	$100,000,000	
Wells Fargo Bank, National Association	$100,000,000	
PNC Bank, National Association	$100,000,000	
KeyBank National Association	$100,000,000	
Credit Agricole Corporate and Investment Bank	$100,000,000	
Total	$500,000,000	

Schedule 4.01(m)

Significant Subsidiaries

None.

Exhibit 10(n)

AMERICAN ELECTRIC POWER
EXECUTIVE SEVERANCE PLAN

(As Amended Through January 4, 2021)

This sets forth the American Electric Power Executive Severance Plan (the “Plan”), as amended and restated as of January 4, 2021. The Plan was initially adopted on January 15, 2014.

ARTICLE I
PURPOSE AND TERM OF PLAN

Section 1.1 Purpose of the Plan. The purpose of the Plan is to provide Eligible Employees with certain severance benefits as described in this Plan in the event the Eligible Employee’s employment with the American Electric Power System is terminated due to an Involuntary Termination or a Good Reason Resignation.

Section 1.2 Characterization and Interpretation of the Plan. The Plan is intended to comply with the requirements of Code section 409A and its related regulations and guidance. Notwithstanding anything in the Plan to the contrary, distributions may only be made under the Plan upon an event and in a manner permitted by Code section 409A or an applicable exemption. If a payment is not made by the designated payment date under the Plan, the payment shall be made by December 31 of the calendar year in which the designated payment date occurs. To the extent that any provision of the Plan would cause a conflict with the requirements of Code section 409A, or would cause the administration of the Plan to fail to satisfy the requirements of Code section 409A, such provision shall be deemed null and void to the extent permitted by applicable law. All payments to be made upon a termination of employment under this Plan may only be made upon a “separation from service” (as that term is defined under Code section 409A and its related regulations and guidance). For purposes of Code section 409A, any right to receive a particular payment or a series of installment payments under this Plan shall be treated as a right to receive separate (or a series of separate) payments. Any right to receive a reimbursement or in-kind benefit provided under the Plan shall be made or provided in accordance with the requirements of Code section 409A, including, where applicable, the requirement that: (i) any reimbursement shall be for expenses incurred during the Participant’s lifetime (or during a shorter period of time specified in this Plan); (ii) the amount of expenses eligible for reimbursement, or in-kind benefits provided, during a calendar year may not affect the expenses eligible for reimbursement, or in-kind benefits to be provided, in any other calendar year; (iii) the reimbursement of an eligible expense will be made on or before the last day of the calendar year following the year in which the expense is incurred; and (iv) the right to reimbursement or in-kind benefits is not subject to liquidation or exchange for another benefit

Section 1.3 Term and Effect of the Plan.

(a)The Plan generally shall be effective as of the Effective Date and, except to the extent otherwise specified in the Plan, shall supersede any prior plan, program, policy, or agreement under which the AEP System Companies provided severance benefits prior to the Effective Date of the Plan for the Eligible Employees. However, the Plan shall not be construed so as to supersede any prior or existing plan, program, policy or agreement (or any portion of such prior arrangement) pursuant to which an Eligible Employee accrued benefits other than severance benefits.

(b)Notwithstanding the foregoing, the Plan shall not: (i) apply to any Employee who is subject to an existing employment or severance agreement pursuant to which the Company or any of the other AEP System Companies has arranged to provide severance benefits to the Employee until the term of such agreement expires (or, if earlier, such date as the Employee executes an acknowledgement that this Plan supersedes such agreement); or (ii) supersede any plan, program, policy or agreement pursuant to which the Company or any of the other AEP System Companies has arranged to provide severance benefits to an Employee in connection with the occurrence of a change in control.

(c)The Plan shall continue until terminated pursuant to Article VIII of the Plan.

ARTICLE II
DEFINITIONS

Section 2.1 “AEP” shall mean American Electric Power Company, Inc., the Company’s parent, and any successor to all or a major portion of the assets or business of American Electric Power Company, Inc.

Section 2.2 “AEP System Companies” shall mean all subsidiaries, affiliates, divisions, organizations and related entities of American Electric Power Company, Inc., and any successor or assigns of any of the foregoing.

Section 2.3 “Annual Salary” shall mean the Participant’s regular annual base salary immediately prior to the Participant’s Termination of employment, including compensation converted to other benefits under a flexible pay arrangement maintained by the Company or deferred pursuant to a written plan or agreement with the Company, but excluding sign-on bonuses, allowances and compensation paid or payable under any AEP System Company long-term or short-term incentive plans or any similar payments, and any salary lump sum amount paid in lieu of or in addition to a base wage or salary increase.

Section 2.4 “Board” shall mean the Board of Directors of AEP, or any successor thereto.

Section 2.5 “Cause” shall mean any one or more of the following grounds for the Termination of the employment of an Employee: (i) failure or refusal to perform a substantial part
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of the Employee’s assigned duties and responsibilities following notice and a reasonable opportunity to cure (if such failure is capable of cure); (ii) commission of an act of willful misconduct, fraud, embezzlement or dishonesty either in connection with the Employee's duties to any AEP System Company or which otherwise is injurious to the best interest or reputation of any AEP System Company; (iii) repeated failure to follow specific lawful directions of the Board or any officer to whom the Employee reports; (iv) a violation of any of the material terms and conditions of any written agreement or agreements the Employee may from time to time have with an AEP System Company; (v) a material violation of any of the rules of conduct of behavior of any AEP System Company, such as may be provided in any employee handbook or as an AEP System Company may promulgate from time to time, following notice and a reasonable opportunity to cure (if such violation is capable of cure); (vi) conviction of, or plea of guilty or nolo contendere to, (A) a felony, (B) a misdemeanor involving an act of moral turpitude, or (C) a misdemeanor committed in connection with the Employee’s employment with any AEP System Company which is injurious to the best interest or reputation of any AEP System Company; or (vii) violation of any applicable confidentiality, non-solicitation, or non-disparagement covenants or obligations relating to any AEP System Company (including, without limitation, the covenants set forth in Article VI). The Committee, in its sole and absolute discretion, shall determine Cause.

Section 2.6 “Change in Control Termination” shall mean an Eligible Employee’s termination of employment that occurs in connection with a change in control and that results in the Employee receiving severance payments or other benefits under the American Electric Power Service Corporation Change In Control Agreement or any other plan, program, agreement or arrangement on account of such change in control. For purposes of this Section, the term “change in control” shall have the meaning as defined in the American Electric Power Service Corporation Change In Control Agreement or such other plan, program, agreement or arrangement, as applicable.

Section 2.7 “Code” shall mean the Internal Revenue Code of 1986, as amended.

Section 2.8 “Committee” shall mean the Human Resources Committee of the Board or such other committee to which the Board has delegated the functions of its Human Resources Committee. The Committee may delegate all or a portion of its authority under the Plan to an individual or another committee.

Section 2.9 “Company” shall mean American Electric Power Service Corporation and any successor to all or a major portion of the assets or business of American Electric Power Service Corporation.

Section 2.10 “Disability” or “Disabled” means that the Eligible Employee has an illness or injury for which the Eligible Employee has been determined to be entitled to benefits under the terms of the LTD Plan. An Eligible Employee shall not be considered Disabled for purposes of this Plan effective at any time the Eligible Employee is not entitled to benefits under the LTD Plan, under such circumstances that include (but are not limited to) the termination of the LTD Plan or the Employee not being in a classification eligible to participate in the LTD Plan.
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Section 2.11 “Effective Date” shall mean January 1, 2014.

Section 2.12 “Eligible Employee” shall mean an Employee of the Company, an AEP System Company or AEP who is designated by the Company, in its sole discretion, and approved by the Committee in its sole discretion (or by the Chief Executive Officer of the Company in his or her sole discretion to the extent so delegated by the Committee) as an employee entitled to benefits, if any, under the terms of this Plan.

Section 2.13 “Employee” shall mean a person who receives salary, wages or commissions from the AEP System Companies that are subject to withholding for the purposes of federal income and employment taxes. The term Employee shall not include an independent contractor or any other person who the Committee or its designee determines is not subject to withholding for purposes of federal income and employment taxes, regardless of any contrary governmental or judicial determination relating to such employment or withholding tax status.

Section 2.14 “Employer” shall mean the Company or any of the AEP System Companies with respect to which this Plan has been adopted.

Section 2.15 “ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended, and regulations thereunder.

Section 2.16 “Exchange Act” shall mean the Securities Exchange Act of 1934, as amended.

Section 2.17 “Good Reason Resignation” shall mean an Eligible Employee’s written resignation within 60 days of the occurrence of any reduction in the Eligible Employee’s then-current annual Base Salary without the Eligible Employee’s consent, unless such events are fully corrected by the Employer within ten days following receipt of written notice from the Eligible Employee; provided, however, that a uniform percentage reduction of 10% or less in the annual Base Salary of all Eligible Employees determined by the Committee to be similarly situated shall not constitute a basis for a Good Reason Resignation.

Section 2.18 “Involuntary Termination” shall mean an Eligible Employee’s termination of employment initiated by the AEP System Companies for any reason other than Cause as provided under and subject to the conditions of Article III. Involuntary Termination does not include a termination of employment due to Mandatory Retirement, Disability or death. An Eligible Employee’s employment also shall not be considered an Involuntary Termination if, within thirty (30) days after the Termination Date, the Eligible Employee receives an offer of employment with a Purchaser Employer, a Successor or an AEP System Company that is at the same or higher annual Base Salary and Target Bonus.

Section 2.19 “LTD Plan” means the American Electric Power System Long Term Disability Plan, as amended from time to time, or any plan providing continuation of cash payments due to an Eligible Employee’s illness or injury that may reasonably be expected to prevent the Eligible Employee from performing the duties of the Eligible Employee’s occupation
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for a period longer than at least 6 months that is designated as a successor to that plan or as a replacement for that plan with respect to the Eligible Employee.

Section 2.20 “LTIP” shall mean the American Electric Power System Long-Term Incentive Plan, as amended from time to time, including any successor or replacement plan under which restricted stock units and performance shares are awarded.

Section 2.21 “Mandatory Retirement” means a Participant’s Termination, if all of the following conditions are satisfied: (i) the Participant is an executive of one or more AEP System Companies subject to mandatory retirement at age 65, and (ii) the Participant’s employment with the AEP System Companies Terminates on the date the Participant attains age 65 or such later date specified by resolution of the Board (or such person or committee to whom the Board delegates the authority to make such determinations) adopted prior to the date the Participant attains age 65.

Section 2.22 “Participant” shall mean any Eligible Employee who meets the requirements of Article III and thereby becomes eligible for benefits under the Plan.

Section 2.23 “Performance Units” shall have the meaning specified in any document issued by the Company as a Performance Unit Award Agreement pursuant to the LTIP and that remain outstanding.

Section 2.24 “Plan” shall mean the American Electric Power Executive Severance Plan as set forth herein, and as the same may from time to time be amended.

Section 2.25 “Plan Administrator” shall mean the individual(s) appointed by the Committee to administer the terms of the Plan as set forth herein and if no individual is appointed by the Committee to serve as the Plan Administrator for the Plan, the Plan Administrator shall be the employee of the Company who heads up the Human Resources department. Notwithstanding the preceding sentence, in the event the Plan Administrator is entitled to Severance Benefits under the Plan, the Committee or its delegate shall act as the Plan Administrator for purposes of administering the terms of the Plan with respect to the Plan Administrator. The Plan Administrator may delegate all or any portion of its authority under the Plan to any other person(s).

Section 2.26 “Release” shall mean the Severance, Release of All Claims and Noncompetition Agreement in substantially the form attached as Exhibit A, whereby the Participant agrees (a) to waive and release the Company, AEP, all AEP System Companies and all affiliated persons and entities, including their respective officers, directors, employees, agents, and representatives of and from any and all claims, demands and causes of action; and (b) not to, during the 12-month period following the Participant’s Termination Date (the “Restricted Period”), without the Company’s prior written consent, for any reason, directly or indirectly either as principal, agent, manager, employee, partner, shareholder, director, officer, consultant or otherwise become engaged or involved, in a manner that relates to or is similar in nature to the specific duties performed by the Participant at any time during his or her employment with any
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AEP System Company, in any business (other than as a less-than three percent (3%) equity owner of any corporation traded on any national, international or regional stock exchange or in the over-the-counter market) that directly competes with the Company or any of the AEP System Companies in

(i)the business of the harnessing, production, transmission, distribution, marketing or sale of electricity; or the development or operation of transmission facilities or power generation facilities; or

(ii)any other business in which the Company or any of the AEP System Companies is engaged at the termination of the Participant's employment with the AEP System Companies.

The provisions of this Section 2.26(b) shall be limited in scope and be effective only within one or more of the following geographical areas: (A) any state in the United States where the Company, including the AEP System Companies, has at least U.S. $25 million in capital deployed as of the Participant’s Termination Date; or (B) any state or country with respect to which was conducted a business of any of the AEP System Companies, which business, or oversight of which business, constituted any part of the Participant’s employment. The parties intend the above geographical areas to be completely severable and independent, and any invalidity or unenforceability of the Release with respect to any one area shall not render the Release unenforceable as applied to any one or more of the other areas. Nothing in this Section 2.26(b) shall be construed to prohibit the Participant being retained during the Restricted Period in a capacity as an attorney licensed to practice law, or to restrict the Participant from providing advice and counsel in such capacity, in any jurisdiction where such prohibition or restriction is contrary to law.

Section 2.27 “Restricted Stock Unit” or “RSU” shall have the meaning set forth in the terms of each Restricted Stock Unit Award Agreement issued to the Participant under the LTIP.

Section 2.28 “Severance Benefits” shall mean the severance benefits that a Participant is eligible to receive pursuant to Article IV, subject to adjustment pursuant to Article X.

Section 2.29 “Successor” shall mean any other corporation or unincorporated entity or group of corporations or unincorporated entities which acquires ownership, directly or indirectly, through merger, consolidation, purchase or otherwise, of all or substantially all of the assets of the Company or AEP.

Section 2.30 “Target Annual Incentive Payment” shall mean shall mean the award that the Participant would have received under the annual incentive compensation plan applicable to such Participant for the year in which the Participant’s Termination occurs, if one hundred percent (100%) of the annual target award has been earned. Participants not participating in an annual incentive compensation plan that has predefined target levels will be treated as though they were participants in an annual incentive plan with such targets and will be assigned the same annual target percent as their participating peers in a comparable salary grade.
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Section 2.31 “Termination Date” shall mean the date on which the active employment of the Eligible Employee by the AEP System Companies is severed for any reason, provided that the Termination Date shall not include any date that would not be considered to be a separation from service, determined in a manner consistent with the written policies adopted by the Committee from time to time to the extent such policies are consistent with the requirements imposed under Code Section 409A(a)(2)(A)(i).

Section 2.32 “General Severance Plan” shall mean the American Electric Power Company, Inc. Severance Plan as amended from time to time.

Section 2.33 “Purchaser Employer” shall mean any other corporation or unincorporated entity or group of corporations or unincorporated entities that acquires (in one transaction or a series of transactions, whether by purchase, merger, consolidation, reorganization or otherwise) Control of the AEP System Company that employs the Eligible Employee or of an AEP System Company or business unit of an AEP System Company for which such Eligible Employee has significant work responsibility. Solely for purposes of this Section, the term “Control” shall mean

(i)     ownership, directly or indirectly, of more than 50% of the then outstanding stock or of any class of equity interest or voting interest in such AEP System Company or business unit; or
(ii) ownership, directly or indirectly, of all or substantially all of the assets of such AEP System Company or business unit.

The term “Purchaser Employer” also shall include all entities that control, that are controlled by or that are under common control with any such acquiring corporation or entity.
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ARTICLE III
PARTICIPATION AND ELIGIBILITY FOR BENEFITS

Section 3.1 Participation. Each Eligible Employee in the Plan who incurs an Involuntary Termination or a Good Reason Resignation (other than an Involuntary Termination or Good Reason Resignation that constitutes a Change in Control Termination) and who satisfies the conditions of Section 3.2 shall be eligible to receive the Severance Benefits described in the Plan. An Eligible Employee shall not be eligible to receive any other severance benefits from the AEP System Companies on account of an Involuntary Termination or a Good Reason Resignation, unless otherwise provided in the Plan; provided that if the facts and circumstances surrounding the termination of employment of such an Eligible Employee satisfies the requirements to receive the benefits under both this Plan and the General Severance Plan, such Eligible Employee shall not be precluded from receiving benefits under the General Severance Plan, provided that the benefits provided to such a Participant under this Plan shall be adjusted in the manner described in Article X.

Section 3.2 Conditions.

(a) Eligibility for any Severance Benefits is expressly conditioned on the satisfaction of all of the following conditions:

(i)an Eligible Employee’s written acknowledgment and agreement to comply with the provisions in Article VI during and after the Eligible Employee’s employment with the AEP System Companies within such period as may be requested by the Company;

(ii)to the extent requested by the Company, execution of a written acknowledgement and agreement that this Plan supersedes an existing arrangement that provides severance benefits to the Eligible Employee and/or that the Eligible Employee is no longer entitled to receive severance benefits pursuant to a prior arrangement that has expired;

(iii)execution and return to the Company of the Release (in the form provided by the Company) by the Participant within 60 days following the Participant’s Termination Date (or such shorter period of time specified in the Release); and

(iv)execution by the Participant of a written agreement that authorizes the deduction of amounts owed to the Company prior to the payment of any Severance Benefits (or in accordance with any other schedule as the Committee may, in its sole discretion, determine to be appropriate); provided, that the Committee determines in its sole discretion that such deduction is not in violation of Code section 409A.

(b) If the Committee determines, in its sole discretion, that the Participant has not fully complied with any of the terms of the Release, the Committee may deny Severance Benefits not yet in pay status or discontinue the payment of the Participant’s Severance Benefits and may
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require the Participant, by providing written notice of such repayment obligation to the Participant, to repay any portion of the Severance Benefits already received under the Plan. If the Committee notifies a Participant that repayment of all or any portion of the Severance Benefits received under the Plan is required, such amounts shall be repaid within 30 calendar days of the date the written notice is sent. Any remedy under this paragraph (b) shall be in addition to, and not in place of, any other remedy, including injunctive relief, that any AEP System Company may have.

(c) An Eligible Employee who experiences a termination of employment that is not an Involuntary Termination or a Good Reason Resignation shall not be eligible to receive Severance Benefits under the Plan. Specifically, and without limiting the foregoing, an Eligible Employee shall not be eligible to receive Severance Benefits upon the Eligible Employee’s:

(i)voluntary resignation or retirement (other than a voluntary resignation or retirement that constitutes a Good Reason Resignation);

(ii)Change in Control Termination;

(iii)resignation of employment (other than a Good Reason Resignation) before the job-end date specified by the Employer or while the Employer still desires the Eligible Employee’s services;

(iv)termination for Cause;

(v)termination due to death or Permanent Disability; or

(vi)failure to return to work within six months of the onset of an approved leave of absence to the extent such failure to return to work itself constitutes a separation from service, determined in a manner consistent with the written policies adopted by the Committee from time to time to the extent such policies are consistent with the requirements imposed under Code Section 409A(a)(2)(A)(i).

Further, except under circumstances specified in this Plan, an Eligible Employee shall not be eligible to receive Severance Benefits upon his termination of employment if the Eligible Employee receives severance benefits pursuant to another plan, policy, program or arrangement providing benefits upon a termination of employment or other separation from service.

(d) Except as otherwise set forth herein, the Committee has the sole discretion to determine an Eligible Employee’s eligibility to receive Severance Benefits.

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ARTICLE IV
DETERMINATION OF SEVERANCE BENEFITS

Section 4.1 Amount of Severance Benefits Upon Involuntary Termination or Good Reason Resignation. The Severance Benefits to be provided to a Participant who incurs an Involuntary Termination or a Good Reason Resignation and who satisfies the conditions of Section 3.2 shall be as follows:

(a) Salary and Bonus Severance. Participants shall receive salary and bonus severance payment equal to 100% of the sum of (A) the Participant’s Base Salary, plus (B) the Participant’s Target Annual Incentive Payment (with both Base Salary and Target Annual Incentive Payment being determined without regard to any decrease in such Base Salary or Target Annual Incentive Payment that would constitute a basis for a Good Reason Resignation).

(b) Restricted Stock Unit Awards. Participants shall be considered to have vested in a fractional portion of the Participant’s Restricted Stock Units (and related Dividend Equivalent RSUs) provided that the Participant’s Termination may not otherwise lead to their vesting under the terms of the applicable Restricted Stock Unit Award Agreement issued to the Participant under the LTIP. The portion of Participant’s Granted RSUs (and related Dividend Equivalent RSUs) (as those terms are defined in the applicable Restricted Stock Unit Award Agreement) that vest under this provision is determined as follows:

(i)The number of whole months from the Effective Date defined in the RSU Award Agreement through the Participant’s Termination Date divided by the number of whole months from that Effective Date until the final Vesting Date specified in the Vesting Schedule set forth at the beginning of such RSU Award Agreement;

(ii)Reduced (but not below zero) by the cumulative Percentage of Granted Units for which the Vesting Date specified in the Vesting Schedule has passed as of the date the Participant’s Termination Date.

(c) Performance Unit Awards. A Participant shall be eligible to receive a pro-rated share of any outstanding award of Performance Units granted to a Participant in accordance with the terms of the LTIP (a “Performance Unit Award”), provided that the Participant’s Termination is not due to Termination of Employment Due to the Participant’s Retirement or Triggering Event (as defined in such Performance Unit Award). This pro-rated share of any Performance Unit Award shall be calculated by multiplying: (i) the Performance Unit Award the Participant would have earned for the full performance period based on the performance of the AEP System Companies as determined at the end of the applicable performance period by (ii) a fraction, the numerator of which is the number of full months of the Participant’s participation from the Grant Date specified in the Performance Unit Award until the Termination Date and the denominator of which is the total number of months in the applicable performance period for the Performance Unit Award.
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(d) The provisions of this Plan may provide for payments to the Participant under certain compensation or bonus plans of the AEP System Companies under circumstances where such plans would not otherwise provide for payment thereof. It is the specific intention of the Company that the provisions of this Plan shall supersede any provisions to the contrary in such plans, to the extent permitted by applicable law and that such plans not provide benefits that the Company determines to be duplicative of those provided by this Plan, and such plans shall be deemed to have been amended to correspond with this Plan without further action by the Company, the Committee or the Board.

Section 4.2 Other Terminations. If the Eligible Employee’s employment terminates on account of a reason other than an Involuntary Termination or a Good Reason Resignation or the Eligible Employee does not otherwise satisfy the conditions of Section 3.2, the Eligible Employee shall not be entitled to receive Severance Benefits under this Plan and shall be entitled only to those benefits (if any) as may be available under the Company’s then-existing benefit plans and policies at the time of such termination.

Section 4.3 Termination for Cause. If any Eligible Employee’s employment terminates on account of termination by the Company for Cause, the Eligible Employee shall not be entitled to receive Severance Benefits under this Plan and shall be entitled only to those benefits that are legally required to be provided to the Eligible Employee. Notwithstanding any other provision of the Plan to the contrary, if the Committee determines that an Eligible Employee engaged in conduct that constituted Cause at any time prior to the Eligible Employee’s Termination Date, any Severance Benefits payable to the Eligible Employee under Section 4.1 shall immediately cease, and the Eligible Employee shall be required to return any Severance Benefits paid to the Eligible Employee prior to such determination. If the Company has offset other payments owed to the Eligible Employee under any other plan or program, it may, in its sole discretion, waive its repayment right under this Plan solely with respect to the amount of the offset already taken.

Section 4.4 Reduction of Severance Benefits. The Plan Administrator reserves the right to make deductions in accordance with applicable law for any monies owed to the AEP System Companies by the Participant or the value of the property of the AEP System Companies that the Participant has retained in his or her possession; provided, however, that no such deduction shall be made if the Company determines that such would be inconsistent with the requirements of Code section 409A.

ARTICLE V
METHOD AND DURATION OF PAYMENT OF SEVERANCE BENEFITS

Section 5.1 Method of Payment.

(a) Payment of Cash Severance Benefits. The Severance Benefits described in Sections 4.1(a) to which a Participant is entitled shall be paid to the Participant according to the following payment schedule:

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(i)As of the first regular payroll date of the Company that coincides with or immediately follows the date that is six months after the Participant’s Termination Date, a payment equal to 50% of the amount of the Severance Benefits described in Section 4.1(a); and

(ii)The balance of such benefits shall be paid in 13equal bi-weekly installments as of such number of subsequent regular payroll dates of the Company.

Payment under this Section 5.1(a) shall be made by mailing to the last address provided by the Participant to the Company or such other reasonable method as determined by the Plan Administrator.

(b) Payment of Restricted Stock Unit Award Severance Benefits. The Restricted Stock Unit Award benefit described in Section 4.1(b) shall be satisfied by converting into a single share of AEP Common Stock each RSU (including each Granted RSU and each vested Dividend Equivalent RSU) that thereupon becomes vested. The shares of AEP Common Stock resulting from the conversion of the vested RSUs shall be delivered to the Participant or to an account set up for the Participant’s benefit with a broker/dealer designated by the Company (the “Broker/Dealer Account”) as of the earlier of (i) six months after the Participant’s Termination Date or (ii) the 15th day of the third month after the calendar year in which falls the Participant’s Termination Date (or the immediately preceding business day of such broker-dealer, if that day is not such a business day). AEP Common Stock and all Participants remain subject to all applicable legal and regulatory restrictions such as insider trading restrictions and black-out periods.

(c) Payment of Performance Unit Award Severance Benefits. Except to the extent required to be deferred, (such as pursuant to the terms of the American Electric Power System Stock Ownership Requirement Plan, the American Electric Power System Incentive Compensation Deferral Plan or any similar or successor plan), the Performance Unit Award benefit described in Section 4.1(c) shall be paid following the completion of the applicable performance period for the Performance Award, but in no event later than two and one-half months thereafter.

(d) Taxes. All payments of Severance Benefits are subject to applicable federal, state and local taxes and withholdings. The Company, in its discretion, may reduce the number of shares of AEP Common Stock delivered to the Participant under Section 5.1(b) to satisfy such tax withholding obligation. The amount of such reduction shall be based upon the Fair Market Value (as defined in the LTIP) of AEP Common Stock at that time; provided, however, that any reduction to a Participant’s vested RSUs for applicable tax withholding shall not exceed such limits as may be applicable to comply with the requirements of Code Section 409A.

(e) Participant’s Death; No Interest. In the event of the Participant’s death prior to payment being made, the amount of such payment shall be paid in accordance with the terms of an applicable award, or to the extent not specified by such award, to the Participant’s estate. In no event will interest be credited on the unpaid balance for which a Participant may become eligible.

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Section 5.2 Termination of Eligibility for Benefits. Eligible Employees shall cease to be eligible to participate in the Plan, and the payment of all Severance Benefits shall cease upon the occurrence of the earlier of: (i) subject to Article VIII, termination or modification of the Plan; or (ii) completion of payment to the Participant of the Severance Benefits for which the Participant is eligible under Article IV. Further, notwithstanding anything in the Plan to the contrary, the Committee shall have the right to cease the payment of all Severance Benefits and to recover payments previously made to the Participant should the Participant at any time breach the Participant’s undertakings under the terms of the Plan (including, without limitation, a determination that the Participant engaged in conduct that constitutes Cause), the Release the Participant executed to obtain the Severance Benefits under the Plan, or the covenants set forth in Article VI.

ARTICLE VI
COVENANTS

Section 6.1 General. Upon the Eligible Employee’s execution of the written acknowledgment and agreement referred to in Section 3.2, the Eligible Employee shall be subject to the covenants described in this Article VI during the Eligible Employee’s period of employment with the AEP System Companies and at any time thereafter (except to the extent the duration of a covenant extending after an Eligible Employee’s termination of employment is specifically limited as described below).

Section 6.2 Confidential Information.

(a) The Eligible Employee acknowledges that all Confidential Information (as defined below) shall at all times remain the property of the AEP System Companies. For purposes of this Plan, “Confidential Information” means all information including, but not limited to, proprietary information and/or trade secrets, and all information disclosed to the Eligible Employee or known by the Eligible Employee as a consequence of or through the Eligible Employee’s employment, which is not generally known to the public or in the industry in which the AEP System Companies are or may become engaged, about the AEP System Companies’ businesses, products, processes, and services, including, but not limited to, information relating to research, development, computer program designs, computer data, flow charts, source or object codes, products or services under development, pricing and pricing strategies, marketing and selling strategies, power generating, servicing, purchasing, accounting, engineering, costs and costing strategies, sources of supply, customer lists, customer requirements, business methods or practices, training and training programs, and the documentation thereof. It will be presumed that information supplied to the AEP System Companies from outside sources is Confidential Information unless and until it is designated otherwise.

(b) The Eligible Employee will safeguard, to the extent possible in the performance of his work for the AEP System Companies, all documents and things that contain or embody Confidential Information. Except in the course of the Eligible Employee’s duties to the AEP System Companies or as may be compelled by law or appropriate legal process, the Eligible
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Employee will not, during his employment by the AEP System Companies, or permanently thereafter, directly or indirectly use, divulge, disseminate, disclose, lecture upon, or publish any Confidential Information, without having first obtained written permission from the AEP System Companies to do so; provided, however, that the foregoing shall not prohibit or impede the Eligible Employee from reporting an act or event, that the Eligible Employee in good faith believes is a violation of law, to a relevant law-enforcement agency (such as a federal, state or local law enforcement agency or official), or to a federal, state or local government agency, such as the Securities and Exchange Commission, the Internal Revenue Service, the Equal Employment Opportunity Commission, the Occupational Safety and Health Administration or the Department of Labor, or from cooperating in an investigation conducted by or communicating with such a government agency, or otherwise making disclosures to such an agency, in each case, that are protected under federal, state or local whistleblower laws (“Permissible Disclosures”).

Moreover, pursuant to the federal Defend Trade Secrets Act of 2016 (“DTSA”), (i) no individual will be held criminally or civilly liable under any federal or state trade secret law for the disclosure of a trade secret that is made: (A) in confidence to a federal, state, or local government official, either directly or indirectly, or to an attorney; and made solely for the purpose of reporting or investigating a suspected violation of law; or (B) in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal so that it is not made public; and (ii) an individual who is pursuing a lawsuit for retaliation by an employer for reporting a suspected violation of law may disclose trade secret information to the attorney of the individual and use the trade secret information in the court proceeding, if the individual (A) files any document that contains or reflects the trade secret under seal; and (B) does not disclose any trade secret except as permitted by court order.

An Eligible Employee does not need the prior authorization of (or to give notice to) the AEP System Companies regarding any such Permissible Disclosures or disclosures protected by the DTSA. Notwithstanding the foregoing, no provision in this Plan or in any Release shall be construed or interpreted as authorization from the AEP System Companies for an Eligible Employee to disclose any information covered by the AEP System Companies’ attorney-client or attorney work product privileges or a waiver of any such privilege.

Section 6.3 Non-Solicitation. The Eligible Employee agrees that, during his employment with the AEP System Companies and for a period of two years following the termination of his employment, whether the termination is initiated by the Company or the Eligible Employee, the Eligible Employee shall not, directly or indirectly,

(i)solicit or induce, or attempt to solicit or induce, any employee of the AEP System Companies to leave the AEP System Companies for any reason whatsoever,

(ii)solicit the services of any employee of the AEP System Companies, nor

(iii)induce or attempt to induce any customer, client, supplier, agent or independent contractor of the Company or any of the AEP System Companies to reduce,
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terminate, restrict or otherwise alter its business relationship with the Company or any other AEP System Company,

unless the Company provides the Eligible Employee with its prior, express written consent. Notwithstanding the foregoing, the Participant shall not be subject to the requirements of this Section 6.5 if the Company or any of the AEP System Companies materially breach their obligations under the Plan.

Section 6.4 Return of Confidential Information. Upon termination of the Eligible Employee’s employment, for whatever reason, whether the termination is initiated by the Company or the Eligible Employee, or upon request by the AEP System Companies, the Eligible Employee will deliver to the AEP System Companies all Confidential Information including, but not limited to, the originals and all copies of notes, sketches, drawings, specifications, memoranda, correspondence and documents, records, notebooks, computer systems, computer disks and computer tapes and other repositories of Confidential Information then in the Eligible Employee’s possession or under the Eligible Employee’s control, whether prepared by the Eligible Employee or by others.

Section 6.5 Cooperation. If the Eligible Employee’s employment with the AEP System Companies is terminated, following the Termination Date, the Eligible Employee agrees to reasonably cooperate with the AEP System Companies and their counsel in connection with any matter that arises from or relates to the Eligible Employee’s relationship with the AEP System Companies by providing information, reviewing documents, answering questions, or appearing as a witness in connection with any administrative proceeding, investigation, or litigation; provided, that such cooperation will not interfere with the Eligible Employee’s commitment and responsibilities with any subsequent employer. The AEP System Companies will pay the Eligible Employee’s reasonable expenses, including travel, incurred in connection with such cooperation.

Section 6.6 Non-Disparagement. Each of the Eligible Employees agrees not to make any statements that disparage the AEP System Companies, their respective affiliates, employees, officers, directors, products, or services. Notwithstanding the foregoing, statements made in the course of sworn testimony in administrative, judicial, or arbitral proceedings (including, without limitation, depositions in connection with such proceedings) shall not be subject to this Section 6.6.

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Section 6.7 Equitable Relief.

(a) By participating in the Plan, the Eligible Employee acknowledges that the restrictions contained in this Article VI are reasonable and necessary to protect the legitimate interests of the AEP System Companies, that the Company would not have established this Plan in the absence of such restrictions, and that any violation of any provision of this Article VI will result in irreparable injury to the AEP System Companies. By agreeing to participate in the Plan, the Eligible Employee represents that his or her experience and capabilities are such that the restrictions contained in this Article VI will not prevent the Eligible Employee from obtaining employment or otherwise earning a living at the same general level of economic benefit as is currently the case.

(b) The Eligible Employee agrees that the AEP System Companies shall be entitled to preliminary and permanent injunctive relief, without the necessity of proving actual damages, as well as an equitable accounting of all earnings, profits, and other benefits arising from any violation of this Article VI, which rights shall be cumulative and in addition to any other rights or remedies to which the AEP System Companies may be entitled. It is the intention of the parties that the provisions of this Article VI shall be enforceable to the fullest extent permissible by law. If any of the provisions in this Article VI are hereafter construed to be invalid or unenforceable in any jurisdiction, the same shall not affect the remainder of the provisions in this Article VI or the enforceability therein in any other jurisdiction where such provisions shall be given full effect. If any provision of this Article VI shall be deemed unenforceable, in whole or in part, this Article VI shall be deemed to be amended to delete or modify the offending part so as to alter this Article VI to render it valid and enforceable.

(c) The Eligible Employee irrevocably and unconditionally: (i) agrees that any suit, action, or other legal proceeding arising out of this Article VI, including without limitation, any action commenced by the AEP System Companies for preliminary and permanent injunctive relief or other equitable relief, may be brought in the United States District Court for the Southern District of Ohio, or if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Ohio; (ii) consents to the non-exclusive jurisdiction of any such court in any such suit, action or proceeding; (iii) waives any right to a jury trial; and (iv) waives any objection which the Eligible Employee may have to the laying of venue of any such suit, action or proceeding in any such court. Eligible Employees also irrevocably and unconditionally consent to the service of any process, pleadings, notices or other papers in a manner permitted by the notice provisions of Section 9.2.

Section 6.8 Survival of Provisions. The obligations contained in this Article VI shall survive the termination of an Eligible Employee’s employment with the AEP System Companies and shall be fully enforceable thereafter.

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ARTICLE VII
PLAN ADMINISTRATION; DUTIES OF THE COMPANY, THE COMMITTEE AND
THE PLAN ADMINISTRATOR; AND CLAIMS

Section 7.1 Authority and Duties. It shall be the duty of the Plan Administrator, on the basis of information supplied to it by the Company and the Committee, to properly administer the Plan. The Plan Administrator shall have the full power, authority, and discretion to construe, interpret, and administer the Plan, to make factual determinations, to correct deficiencies therein, and to supply omissions. All decisions, actions, and interpretations of the Plan Administrator shall be final, binding, and conclusive upon the parties, subject only to determinations by the Plan Administrator, with respect to denied claims for Severance Benefits. The Plan Administrator may adopt such rules and regulations and may make such decisions as it deems necessary or desirable for the proper administration of the Plan. The Plan Administrator shall be a “named fiduciary” within the meaning of ERISA.

Section 7.2 Payment. Payments of Severance Benefits to Participants shall be made in such amount as determined by the Committee under Article IV (subject to adjustment as set forth in Article X), from the Company’s general assets, in accordance with the terms of the Plan, as directed by the Committee.

Section 7.3 Discretion. Any decisions, actions or interpretations to be made under the Plan by the Board, the Committee and the Plan Administrator, acting on behalf of either, shall be made in each of their respective sole discretion, not in any fiduciary capacity and need not be uniformly applied to similarly situated individuals and such decisions, actions or interpretations shall be final, binding and conclusive upon all parties. As a condition of participating in the Plan, each Eligible Employee acknowledges that all decisions and determinations of the Board, the Committee, and the Plan Administrator shall be final and binding on the Eligible Employee, his or her beneficiaries, and any other person having or claiming an interest under the Plan on his or her behalf; provided, however, that the Eligible Employee shall have the right to challenge any such decisions and determinations in accordance with the claims and appeals procedures set forth in Section 7.4 and applicable law.

Section 7.4 Claims Administration.

(a) Each Participant under this Plan may make a claim for benefits under the Plan by completing and filing with the Plan Administrator a written request for review in the manner specified by the Plan Administrator. No person may bring an action for any alleged wrongful denial of Plan benefits in a court of law unless the claims procedures described in this Article VII are exhausted and a final determination is made by the Plan Administrator. If the terminated Participant or interested person challenges a decision by the Plan Administrator, a review by the court of law will be limited to the facts, evidence and issues presented to the Plan Administrator during the claims procedure set forth in this Article VII. Facts and evidence that become known to the terminated Participant or other interested person after having exhausted the claims procedure must be brought to the attention of the Plan Administrator for reconsideration. Issues not raised with the Plan Administrator will be deemed waived.

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(b) Before the date on which payment of Severance Benefits commence, each such application must be supported by such information as the Plan Administrator deems relevant and appropriate. In the event that any claim relating to the administration of Severance Benefits is denied in whole or in part, the terminated Participant or his or her beneficiary (the “Claimant”) whose claim has been so denied shall be notified of such denial in writing by the Plan Administrator within 90 days after the receipt of the claim for benefits. This period may be extended an additional 90 days if the Plan Administrator determines such extension is necessary and the Plan Administrator provides notice of extension to the Claimant prior to the end of the initial 90-day period. The notice advising of the denial shall specify the following: (i) the reason or reasons for denial; (ii) make specific reference to the Plan provisions on which the determination was based; (iii) describe any additional material or information necessary for the Claimant to perfect the claim (explaining why such material or information is needed); and (iv) describe the Plan’s review procedures and the time limits applicable to such procedures, including a statement of the Claimant’s right to bring a civil action under section 502(a) of ERISA following an adverse benefit determination on review.

(c) A Claimant whose claim has been denied shall file with the Plan Administrator a notice of appeal of the denial. Such notice shall be filed within 60 calendar days of notification by the Plan Administrator of the denial of a claim, shall be made in writing, and shall set forth all of the facts upon which the appeal is based. Appeals not timely filed shall be barred. The Plan Administrator shall consider the merits of the Claimant’s written presentations, the merits of any facts or evidence in support of the denial of benefits, and such other facts and circumstances as the Plan Administrator shall deem relevant.

(d) The Plan Administrator shall render a determination upon the appealed claim which determination shall be accompanied by a written statement as to the reasons therefore. The determination shall be communicated to the Claimant within 60 days of the Claimant’s request for review, unless the Plan Administrator determines that special circumstances require an extension of time for processing the claim. In such case, the Plan Administrator shall notify the Claimant of the need for an extension of time to render its decision prior to the end of the initial 60-day period, and the Plan Administrator shall have an additional 60-day period to make its determination. The determination so rendered shall be binding upon all parties. If the determination is adverse to the Claimant, the notice shall: (i) provide the reason or reasons for denial; (ii) make specific reference to the Plan provisions on which the determination was based; (iii) include a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim for benefits; and (iv) state that the Claimant has the right to bring an action under section 502(a) of ERISA.

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ARTICLE VIII
AMENDMENT, TERMINATION AND DURATION

Section 8.1 Amendment, Suspension and Termination.

(a) Except as otherwise provided in paragraph (b) hereof, the Committee or its delegee shall have the right, at any time and from time to time, to amend, suspend, or terminate the Plan in whole or in part, for any reason or without reason, and without either the consent of or the prior notification to any Eligible Employee, by a formal written action. No such amendment shall give the Company the right to recover any amount paid to a Participant prior to the date of such amendment or to cause the cessation of Severance Benefits already approved for a Participant who has returned to the Company an executed Release as required under Section 3.2 (except as otherwise contemplated by the terms of the Plan).

(b) Any amendment, modification or termination of the Plan undertaken pursuant to paragraph (a) hereof that (i) reduces or eliminates Plan benefits, (ii) terminates the participation of one or more Eligible Employees, or (iii) modifies the notice provisions of this Section 8.1(b), shall be effective 12 months (or such longer period as determined by the Committee or its delegee) after the date that each affected Eligible Employee is provided written notice of such amendment, modification or termination.

Section 8.2 Duration. Unless terminated sooner by the Committee or its delegee, the Plan shall continue in full force and effect until termination of the Plan pursuant to Section 8.1; provided, however, that after the termination of the Plan, if any Participant terminated employment on account of an Involuntary Termination or a Good Reason Resignation prior to the termination of the Plan and is still receiving Severance Benefits under the Plan, the Plan shall remain in effect until all of the obligations of the Company are satisfied with respect to such Participant.

ARTICLE IX
MISCELLANEOUS

Section 9.1 Nonalienation of Benefits. None of the payments, benefits or rights of any Participant shall be subject to any claim of any creditor of any Participant, and, in particular, to the fullest extent permitted by law, all such payments, benefits and rights shall be free from attachment, garnishment (if permitted under applicable law), trustee’s process, or any other legal or equitable process available to any creditor of such Participant. No Participant shall have the right to alienate, anticipate, commute, plead, encumber or assign any of the benefits or payments that he may expect to receive, continently or otherwise, under this Plan.

Section 9.2 Notices. All notices and other communications required hereunder shall be in writing and shall be delivered personally or mailed by registered or certified mail, return receipt requested, or by overnight express courier service. In the case of the Participant, mailed notices shall be addressed to him or her at the home address which he or she most recently communicated
19

to the Company in writing. In the case of the Company, mailed notices shall be addressed to the Plan Administrator.

Section 9.3 Successors. Any Successor to the Company or AEP shall assume the obligations under this Plan and expressly agree to perform the obligations under this Plan.

Section 9.4 Other Payments. Except as otherwise provided in this Plan, no Participant shall be entitled to any cash payments or other severance benefits under any of the Company’s then current severance pay policies for a termination that is covered by this Plan for the Participant.

Section 9.5 No Mitigation. Except as otherwise set forth in the Plan, Participants shall not be required to mitigate the amount of any Severance Benefits provided for in this Plan by seeking other employment or otherwise, nor shall the amount of any Severance Benefits provided for herein be reduced by any compensation earned by other employment or otherwise, except if the Participant is re-employed by the AEP System Companies, in which case Severance Benefits shall cease.

Section 9.6 No Contract of Employment. Neither the establishment of the Plan, nor any modification thereof, nor the creation of any fund, trust or account, nor the payment of any benefits shall be construed as giving any Eligible Employee or any person whosoever, the right to be retained in the service of the AEP System Companies, and all Eligible Employees shall remain subject to discharge to the same extent as if the Plan had never been adopted.

Section 9.7 Severability of Provisions. If any provision of this Plan shall be held invalid or unenforceable by a court of competent jurisdiction, such invalidity or unenforceability shall not affect any other provisions hereof, and this Plan shall be construed and enforced as if such provisions had not been included.

Section 9.8 Heirs, Assigns, and Personal Representatives. This Plan shall be binding upon the heirs, executors, administrators, successors and assigns of the parties, including each Participant, present and future.

Section 9.9 Headings and Captions. The headings and captions herein are provided for reference and convenience only, shall not be considered part of the Plan, and shall not be employed in the construction of the Plan.

Section 9.10 Gender and Number. Where the context admits: words in any gender shall include any other gender, and, except where otherwise clearly indicated by context, the singular shall include the plural, and vice-versa.

Section 9.11 Unfunded Plan. The Plan shall not be funded. No Participant shall have any right to, or interest in, any assets of the AEP System Companies that may be applied by the AEP System Companies to the payment of Severance Benefits.

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Section 9.12 Payments to Incompetent Persons. Any benefit payable to or for the benefit of a minor, an incompetent person or other person incapable of receipting therefore shall be deemed paid when paid to such person’s guardian or to the party providing or reasonably appearing to provide for the care of such person, and such payment shall fully discharge the Company, the Committee and all other parties with respect thereto.

Section 9.13 Lost Payees. A benefit shall be deemed forfeited if the Plan Administrator is unable to locate a Participant to whom Severance Benefits are due. Such Severance Benefits shall be reinstated if application is made by the Participant for the forfeited Severance Benefits while this Plan is in operation.

Section 9.14 Controlling Law. This Plan shall be construed and enforced according to the laws of the State of Ohio without regard to the application of choice of law rules to the extent not superseded by Federal law.

ARTICLE X
COORDINATION WITH GENERAL SEVERANCE PLAN

Section 10.1 Coordination Generally. If a Participant becomes entitled to receive the benefits under both this Plan and the General Severance Plan (a “Dual Participant”), the benefits provided under this Plan shall be adjusted in the manner described in this Article X.

Section 10.2 Salary and Bonus Severance. The amount of cash to be paid to the Dual Participant as Severance Benefits described in Section 4.1(a) shall be reduced (but not below $0) by an amount equal to the lump sum severance allowance calculated under the General Severance Plan (currently set forth in Sections 3.1 or 3.2, as appropriate, of the General Severance Plan), and that reduced amount shall be paid in the time and manner described in Section 5.1(a) of this Plan, notwithstanding any different payment schedule that may be specified in the General Severance Plan.

Section 10.3 Continuation of Medical and Dental Coverage. The provisions of this Plan shall not preclude a Dual Participant from receiving an option to continue medical coverage under the terms and conditions as may then be made available to such Dual Participant (or his or her surviving covered dependents) under the terms of the General Severance Plan (currently set forth in Section 3.3 of the General Severance Plan).

Section 10.4 Administration of Claims Involving Article X. All determinations of regarding entitlement to benefits described in the General Severance Plan shall be made in accordance with the terms set forth in the General Severance Plan. The Committee and the Plan Administrator under this Plan may, in their sole discretion, consult with any one or more individuals who are involved in the administration of the General Severance Plan in connection with making any determinations regarding the Severance Benefits to be provided under this Plan.

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EXHIBIT A
to
American Electric Power Executive Severance Plan

SEVERANCE, RELEASE OF ALL CLAIMS AND NONCOMPETITION AGREEMENT

1. This Severance, Release of All Claims and Noncompetition Agreement ("Agreement") is entered into by and between <<FULLNAME>>, herein after referred to, together with his/her heirs, executors, administrators, successors, assigns and personal representatives, as "Employee", and American Electric Power Company Inc., hereinafter referred to, together with all its past, present and future affiliated, parent and/or subsidiary organizations and divisions, and all past, present and future officers, directors, members, employees and agents of each, in both their individual and representative capacities, as the "Company".

2. Severance Allowance. The Company shall provide Employee [the applicable Severance Benefits described in Section 4.1 of the American Electric Power Executive Severance Plan, as amended], subject to such deductions as required by law including, if applicable, repayment of the pay advance made to Employee on or about April 12, 2001, that is not deducted from other amounts paid or payable to Employee.

3. Consideration. Employee acknowledges that the benefits described in this Agreement are benefits to which he/she would not be entitled but for this Agreement.

4. Release and Waiver of Claims. In exchange for the foregoing benefits, subject to Section 10 of this Agreement (Protected Activity), Employee, on behalf of Employee and his/her heirs, executors, administrators, successors, assigns and personal representatives, hereby releases and forever discharges the Company (as defined in Section 1 of this Agreement) and the Company’s long-term disability plans (including any trustees, custodians and administrators engaged in connection with the administration of claims or assets maintained in connection with any such plans) of and from any and all legal, equitable, and administrative claims and demands of every name, type, act and nature, arising out of or existing by reason of any known or unknown act or inaction whatsoever and occurring directly or indirectly as a result of or prior to execution of this Agreement. This release includes, but is not limited to, any claims, charges, complaints, grievances, causes of action (known or unknown), demands, injuries (whether personal, emotional or other), unfair labor practices, or suits arising, directly or indirectly, out of Employee's employment with and/or separation of employment from the Company, and includes, but is not limited to claims, charges, complaints, actions, grievances, demands or suits which may be, have, or might have been asserted, whether in contract or in tort, and whether under common law or under federal, state or local statute, regulation or ordinance. Claims, actions and demands released herein include but are not limited to those based on allegations of wrongful discharge, retaliation, personal injury and/or breach of contract; those arising under federal, state or local employment discrimination, fair employment practices, and/or wage and hour laws; and for West Virginia employees, those arising under the West Virginia Human Rights Act; those arising under
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Title VII of the Civil Rights Act of 1964, the Civil Rights Act of 1866, as amended, the Fair Labor Standards Act, the Age Discrimination in Employment Act of 1967 (“ADEA”), the Rehabilitation Act of 1973, the Americans With Disabilities Act (“ADA”) and Executive Order 11246, (all as amended); those arising under the Uniformed Services Employment and Re-employment Rights Act of 1994 (“USERRA”), the Worker Adjustment and Retraining Notification Act (“WARN”), the Labor Management Relations Act (“LMRA”), the National Labor Relations Act (“NLRA”), and the Family and Medical Leave Act (“FMLA”); and those arising under applicable securities laws. Also released are any claims and demands related to entitlement to long-term disability benefits under any Company long-term disability plan. Excluded from this Agreement are any pending or as yet unaccrued worker’s compensation/occupational disease claims, vested pension and savings plan (401k) benefits, participation in health and welfare benefits (medical, dental and vision) under the terms of such plans, vested baances and payments under non-qualified deferred compensation plans, and claims which cannot be waived by law. Employee is waiving any right to recover any individual relief from the Company (including back pay, front pay, reinstatement or other legal or equitable relief) in any charge, complaint, lawsuit or other proceeding brought by Employee or on Employee's behalf against the Company pertaining to events occurring directly or indirectly as the result of or prior to execution of this Agreement.
5. Agreement Not to Compete. Employee agrees not to, during the [12 or 24, as applicable]-month period following the Employee’s Termination Date (the “Restricted Period”), without the Company’s prior written consent, for any reason, directly or indirectly either as principal, agent, manager, employee, partner, shareholder, director, officer, consultant or otherwise, become engaged or involved, in a manner that relates to or is similar in nature to the specific duties performed by the Employee at any time during his or her employment with any the Company, in any business (other than as a less-than three percent (3%) equity owner of any corporation traded on any national, international or regional stock exchange or in the over-the-counter market) that directly competes with the Company in

(i)     the business of the harnessing, production, transmission, distribution, marketing or sale of electricity; or the development or operation of transmission facilities or power generation facilities; or

(ii) any other business in which the Company is engaged at the termination of the Employee's employment with the Company.

The provisions of this Section 5 shall be limited in scope and be effective only within one or more of the following geographical areas: (A) any state in the United States where the Company has at least U.S. $25 million in capital deployed as of the Employee’s Termination Date; or (B) any state or country with respect to which the Company conducted a business, which, or oversight of which, constituted any part of the Employee’s employment. The parties intend the above geographical areas to be completely severable and independent, and any invalidity or unenforceability of this Agreement with respect to any one area shall not render this Agreement unenforceable as applied to any one or more of the other areas. Nothing in this Section 5 shall be construed to prohibit the Employee being retained during the Restricted Period in a capacity as an
23

attorney licensed to practice law, or to restrict the Employee from providing advice and counsel in such capacity, in any jurisdiction where such prohibition or restriction is contrary to law.

6. Cessation of Employment and (where applicable) LTD Benefits. If Employee has any claim of any benefit entitlement attributable to a disability of Employee, Employee further acknowledges and understands that, as a consequence of accepting the benefits referenced in this Agreement, and signing this Agreement, Employee’s employment with the Company is terminated, the payment (if applicable) of any long-term disability benefits will cease, any claim of entitlement to long-term disability benefits is released, and that any existing reduction of employee contributions toward the cost of medical, dental, life and any other coverages will also cease, subject to Employee’s rights to continuation of coverages pursuant to applicable law. In any event, Employee acknowledges that Employee shall no longer be entitled to any continued employment with the Company.

7. Resignation of Director, Officer and Manager Positions. To the extent Employee has retained any director, officer and/or manager positions with the Company subsequent to Employee’s termination of employment, and to the extent Employee has not already done so, Employee, by executing this Agreement on the date set forth below, hereby resigns, effective immediately, from any and all director, officer and manager positions with the Company.

8. Acknowledgement of Covenants. Employee reaffirms that Employee shall comply with the provisions in Article VI of the American Electric Power Executive Severance Plan, as amended (the “Executive Severance Plan”), during and after the Employee’s employment with the Company.

9. No Admission of Liability. Employee understands that the Company believes that Employee has no valid claim against the Company and that this Agreement is being offered to give Employee a source of income and benefits while he/she attempts to obtain other employment. The fact that this Agreement is offered to the Employee in the first place will not be understood as an indication that the Company believes that Employee has been injured, discriminated against or treated unlawfully in any respect.

10. Protected Activity. (A) Employee understands and acknowledges that nothing in this Agreement prohibits, penalizes, or otherwise discourages him/her from reporting, providing testimony regarding, or otherwise communicating any nuclear safety concern, workplace safety concern, or public safety concern to the U.S. Nuclear Regulatory Commission (NRC) or the U.S. Department of Labor (DOL). Employee further understands and acknowledges that the provisions of this Agreement are not intended to restrict his communication with, or full cooperation in, proceedings or investigations by any agency relating to nuclear regulatory or safety issues. Employee understands that nothing in the Agreement waives his/her right to file a claim with the DOL pursuant to Section 211 of the Energy Reorganization Act, but the Employee expressly waives his/her right to recover any and all damages or other equitable relief, including, but not limited to reinstatement, back pay, front pay, compensatory damages, attorney fees or costs, that may be awarded to the Employee by the DOL as a result of such a claim.

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(B) Nothing in this Agreement (including but not limited to the release and waiver of claims and the confidentiality, cooperation, non-disparagement, return of property and any other limiting provisions) (1) affects or limits Employee’s right to challenge the validity of this Agreement under the ADEA or the Older Workers Benefit Protection Act (where Employee is age 40 or older) or (2) prevents Employee from filing a charge or complaint with, from communicating with or from participating in an investigation or proceeding conducted by, the Equal Employment Opportunity Commission, the Occupational Safety and Health Administration, the National Labor Relations Board, the Securities and Exchange Commission, the Internal Revenue Service, the Department of Justice or any other federal, state or local agency charged with the enforcement of any laws, including providing documents or other information. This Agreement does not limit any right Employee may have, where eligible, to receive an award from a government agency (and not the Company) for information provided to the government agency.

11. Re-employment. Employee agrees and understands that he/she will not seek re-employment with the Company, and that this Agreement shall act as a complete bar to any claim of entitlement to employment or re-employment by the Company.

12. Entire Agreement. Employee and the Company acknowledge that this Agreement contains the entire agreement and understanding of the parties and that no other representation or agreement of any kind whatsoever has been made to Employee by the Company or by any other person or entity to cause Employee to sign this Agreement.

13. Applicable Law . This Agreement shall be governed and interpreted in accordance with the laws of Ohio and applicable federal law.

14. Severability. If any provision of this Agreement is determined to be invalid or unenforceable, the Company and Employee agree that such determination shall not affect the other provisions and that all other provisions shall be enforced as if the invalid provision were not a part of this Agreement.

15. EMPLOYEE NOTICE: PLEASE READ CAREFULLY BEFORE SIGNING THIS SEVERANCE, RELEASE OF ALL CLAIMS AND NONCOMPETITION AGREEMENT.
YOU HAVE TWENTY-ONE (21) CALENDAR DAYS WITHIN WHICH TO CONSIDER THIS AGREEMENT. SHOULD YOU SIGN THE AGREEMENT, YOU HAVE THE RIGHT TO REVOKE IT, IN WRITING, FOR A PERIOD OF SEVEN (7) CALENDAR DAYS AFTER YOU SIGN IT. THIS AGREEMENT SHALL NOT BECOME EFFECTIVE OR ENFORCEABLE UNTIL THE SEVEN-DAY REVOCATION PERIOD HAS EXPIRED.

YOU ARE ADVISED TO CONSULT WITH AN ATTORNEY PRIOR TO SIGNING THIS AGREEMENT. YOU MAY HAVE RIGHTS OR CLAIMS ARISING UNDER THE AGE DISCRIMINATION IN EMPLOYMENT ACT AND/OR OLDER WORKERS BENEFIT PROTECTION ACT. IF YOU WORK IN WEST VIRGINIA, YOU ARE FURTHER
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ADVISED THAT THE TOLL FREE NUMBER OF THE WEST VIRGINIA STATE BAR ASSOCIATION IS 1-800-642-3617.

16. Conclusion. The parties have read the foregoing Severance, and Release of All Claims and Noncompetition Agreement and fully understand it. They now voluntarily sign this Agreement on the date indicated, signifying their agreement and willingness to be bound by its terms.

Employee American Electric Power Company, Inc.

_________________________________ By
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Exhibit 21
Subsidiaries of
American Electric Power Company, Inc.
As of December 31, 2020
Each company shown indented is a subsidiary of the company immediately above which is not indented to the same degree. Subsidiaries not indented are directly owned by American Electric Power Company, Inc.

									
Name of Company		Location of
Incorporation	
American Electric Power Service Corporation		New York	
AEP Energy Supply LLC		Delaware	
AEP Clean Energy Resources, LLC		Delaware	
AEP Generation Resources Inc.		Delaware	
AEP Renewables, LLC		Delaware	
AEP Generating Company		Ohio	
AEP Transmission Holding Company, LLC		Delaware	
AEP Transmission Company, LLC		Delaware	
AEP Indiana Michigan Transmission Company, Inc		Indiana	
AEP Ohio Transmission Company, Inc		Ohio	
AEP Oklahoma Transmission Company, Inc		Oklahoma	
AEP West Virginia Transmission Company, Inc		West Virginia	
AEP Texas Inc.		Delaware	
AEP Texas Central Transition Funding III LLC		Delaware	
AEP Texas North Generation Company LLC		Delaware	
AEP Texas Restoration Funding, LLC		Delaware	
Appalachian Power Company		Virginia	
Appalachian Consumer Rate Relief Funding LLC		Delaware	
Indiana Michigan Power Company		Indiana	
Kentucky Power Company		Kentucky	
Kingsport Power Company		Virginia	
Ohio Power Company		Ohio	
Ohio Valley Electric Corporation		Ohio	
Indiana-Kentucky Electric Corporation		Indiana	
Public Service Company of Oklahoma		Oklahoma	
Southwestern Electric Power Company		Delaware	
Wheeling Power Company		West Virginia	

Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-250106 and 333-249918) and on Form S-8 (Nos. 333-224973, 333-204557, 333-178044) of American Electric Power Company, Inc. of our report dated February 25, 2021 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in the 2020 Annual Report, which is incorporated by reference in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report dated February 25, 2021 relating to the financial statement schedules, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-225325) of AEP Transmission Company, LLC of our report dated February 25, 2021 relating to the financial statements, which appears in the 2020 Annual Report, which is incorporated by reference in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report dated February 25, 2021 relating to the financial statement schedule, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-230613) of AEP Texas Inc. of our report dated February 25, 2021 relating to the financial statements, which appears in the 2020 Annual Report, which is incorporated by reference in this Annual Report on Form 10-K.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-236613) of Appalachian Power Company of our report dated February 25, 2021 relating to the financial statements, which appears in the 2020 Annual Report, which is incorporated by reference in this Annual Report on Form 10-K.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-225103) of Indiana Michigan Power Company of our report dated February 25, 2021 relating to the financial statements, which appears in the 2020 Annual Report, which is incorporated by reference in this Annual Report on Form 10-K.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-230094) of Ohio Power Company of our report dated February 25, 2021 relating to the financial statements, which appears in the 2020 Annual Report, which is incorporated by reference in this Annual Report on Form 10-K.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-251378) of Public Service Company of Oklahoma of our report dated February 25, 2021 relating to the financial statements, which appears in the 2020 Annual Report, which is incorporated by reference in this Annual Report on Form 10-K.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-238159) of Southwestern Electric Power Company of our report dated February 25, 2021 relating to the financial statements, which appears in the 2020 Annual Report, which is incorporated by reference in this Annual Report on Form 10-K.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio
February 25, 2021

Exhibit 24
POWER OF ATTORNEY

AMERICAN ELECTRIC POWER COMPANY, INC.
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 2020

The undersigned directors of AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation (the "Company"), do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and JULIE A. SHERWOOD, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2020, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 10th day of February, 2021.

						
/s/ Nicholas K. Akins	/s/ Sandra Beach Lin	
Nicholas K. Akins	Sandra Beach Lin	
		
/s/ David J. Anderson	/s/ Margaret M. McCarthy	
David J. Anderson	Margaret M. McCarthy	
		
/s/ J. Barnie Beasley, Jr.	/s/ Richard C. Notebaert	
J. Barnie Beasley, Jr.	Richard C. Notebaert	
		
/s/ Ralph D. Crosby, Jr.	/s/ Stephen S. Rasmussen	
Ralph D. Crosby, Jr.	Stephen S. Rasmussen	
		
/s/ Art A. Garcia	/s/ Oliver G. Richard, III	
Art A. Garica	Oliver G. Richard, III	
		
/s/ Linda A. Goodspeed	/s/ Daryl Roberts	
Linda A. Goodspeed	Daryl Roberts	
		
/s/ Thomas E. Hoaglin	/s/ Sara Martinez Tucker	
Thomas E. Hoaglin	Sara Martinez Tucker	

Exhibit 24
POWER OF ATTORNEY

AEP TRANSMISSION COMPANY, LLC
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 2020

The undersigned managers of AEP TRANSMISSION COMPANY, LLC, a Delaware limited liability company (the "Company"), do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and JULIE A. SHERWOOD, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2020, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 11th day of February, 2021.

						
/s/ Nicholas K. Akins	/s/ Julia A. Sloat	
Nicholas K. Akins	Julia A. Sloat	
		
/s/ David M. Feinberg	/s/ A. Wade Smith	
David M. Feinberg	A.Wade Smith	
		
/s/ Mark C. McCullough		
Mark C. McCullough		

Exhibit 24

POWER OF ATTORNEY	
Annual Report on Form 10-K for the Fiscal Year Ended	
December 31, 2020	

The undersigned directors of the following companies (each respectively the "Company")

Company	State of Incorporation	
AEP Texas Inc.
Appalachian Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company	Delaware
Virginia
Ohio
Oklahoma
Delaware	

do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and JULIE A. SHERWOOD, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2020, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 11th day of February, 2021.

						
/s/ Nicholas K. Akins	/s/ Mark C. McCullough	
Nicholas K. Akins	Mark C. McCullough	
		
/s/ Lisa M. Barton	/s/ Charles R. Patton	
Lisa M. Barton	Charles R. Patton	
		
/s/ Paul Chodak, III	/s/ Julia A. Sloat	
Paul Chodak, III	Julia A. Sloat	
		
/s/ David M. Feinberg	/s/ Brian X. Tierney	
David M. Feinberg	Brian X. Tierney	

Exhibit 24

POWER OF ATTORNEY	
Annual Report on Form 10-K for the Fiscal Year Ended	
December 31, 2020	

The undersigned directors of the following companies (each respectively the "Company")

Company	State of Incorporation	
AEP Texas Inc.
Appalachian Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company	Delaware
Virginia
Ohio
Oklahoma
Delaware	

do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and JULIE A. SHERWOOD, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2020, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 11th day of February, 2021.

						
/s/ Nicholas K. Akins	/s/ Mark C. McCullough	
Nicholas K. Akins	Mark C. McCullough	
		
/s/ Lisa M. Barton	/s/ Charles R. Patton	
Lisa M. Barton	Charles R. Patton	
		
/s/ Paul Chodak, III	/s/ Julia A. Sloat	
Paul Chodak, III	Julia A. Sloat	
		
/s/ David M. Feinberg	/s/ Brian X. Tierney	
David M. Feinberg	Brian X. Tierney	

Exhibit 24
POWER OF ATTORNEY

INDIANA MICHIGAN POWER COMPANY
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 2020

The undersigned directors of INDIANA MICHIGAN POWER COMPANY, an Indiana corporation (the "Company"), do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and JULIE A. SHERWOOD, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2020, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 10th day of February, 2021.

						
/s/ Nicholas K. Akins	/s/ David A. Lucas	
Nicholas K. Akins	David A. Lucas	
		
/s/ Lisa M. Barton	/s/ Mark C. McCullough	
Lisa M. Barton	Mark C. McCullough	
		
/s/ Nicholas M. Elkins	/s/ Julia A. Sloat	
Nicholas M. Elkins	Julia A. Sloat	
		
/s/ David M. Feinberg	/s/ Toby L. Thomas	
David M. Feinberg	Toby L. Thomas	
		
/s/ David S. Isaacson	/s/ Brian X. Tierney	
David S. Isaacson	Brian X. Tierney	
		
/s/ Marc E. Lewis		
Marc E. Lewis		

Exhibit 24

POWER OF ATTORNEY	
Annual Report on Form 10-K for the Fiscal Year Ended	
December 31, 2020	

The undersigned directors of the following companies (each respectively the "Company")

Company	State of Incorporation	
AEP Texas Inc.
Appalachian Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company	Delaware
Virginia
Ohio
Oklahoma
Delaware	

do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and JULIE A. SHERWOOD, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2020, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 11th day of February, 2021.

						
/s/ Nicholas K. Akins	/s/ Mark C. McCullough	
Nicholas K. Akins	Mark C. McCullough	
		
/s/ Lisa M. Barton	/s/ Charles R. Patton	
Lisa M. Barton	Charles R. Patton	
		
/s/ Paul Chodak, III	/s/ Julia A. Sloat	
Paul Chodak, III	Julia A. Sloat	
		
/s/ David M. Feinberg	/s/ Brian X. Tierney	
David M. Feinberg	Brian X. Tierney	

Exhibit 24

POWER OF ATTORNEY	
Annual Report on Form 10-K for the Fiscal Year Ended	
December 31, 2020	

The undersigned directors of the following companies (each respectively the "Company")

Company	State of Incorporation	
AEP Texas Inc.
Appalachian Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company	Delaware
Virginia
Ohio
Oklahoma
Delaware	

do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and JULIE A. SHERWOOD, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2020, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 11th day of February, 2021.

						
/s/ Nicholas K. Akins	/s/ Mark C. McCullough	
Nicholas K. Akins	Mark C. McCullough	
		
/s/ Lisa M. Barton	/s/ Charles R. Patton	
Lisa M. Barton	Charles R. Patton	
		
/s/ Paul Chodak, III	/s/ Julia A. Sloat	
Paul Chodak, III	Julia A. Sloat	
		
/s/ David M. Feinberg	/s/ Brian X. Tierney	
David M. Feinberg	Brian X. Tierney	

Exhibit 24

POWER OF ATTORNEY	
Annual Report on Form 10-K for the Fiscal Year Ended	
December 31, 2020	

The undersigned directors of the following companies (each respectively the "Company")

Company	State of Incorporation	
AEP Texas Inc.
Appalachian Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company	Delaware
Virginia
Ohio
Oklahoma
Delaware	

do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and JULIE A. SHERWOOD, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2020, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 11th day of February, 2021.

						
/s/ Nicholas K. Akins	/s/ Mark C. McCullough	
Nicholas K. Akins	Mark C. McCullough	
		
/s/ Lisa M. Barton	/s/ Charles R. Patton	
Lisa M. Barton	Charles R. Patton	
		
/s/ Paul Chodak, III	/s/ Julia A. Sloat	
Paul Chodak, III	Julia A. Sloat	
		
/s/ David M. Feinberg	/s/ Brian X. Tierney	
David M. Feinberg	Brian X. Tierney	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.I have reviewed this report on Form 10-K of American Electric Power Company, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Nicholas K. Akins	
		Nicholas K. Akins	
		Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.I have reviewed this report on Form 10-K of AEP Transmission Company, LLC;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Nicholas K. Akins	
		Nicholas K. Akins	
		Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.I have reviewed this report on Form 10-K of AEP Texas Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Nicholas K. Akins	
		Nicholas K. Akins	
		Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.I have reviewed this report on Form 10-K of Appalachian Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Nicholas K. Akins	
		Nicholas K. Akins	
		Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.I have reviewed this report on Form 10-K of Indiana Michigan Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Nicholas K. Akins	
		Nicholas K. Akins	
		Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.I have reviewed this report on Form 10-K of Ohio Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Nicholas K. Akins	
		Nicholas K. Akins	
		Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.I have reviewed this report on Form 10-K of Public Service Company of Oklahoma;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Nicholas K. Akins	
		Nicholas K. Akins	
		Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.I have reviewed this report on Form 10-K of Southwestern Electric Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. 

Date: February 25, 2021	By:           
 	/s/ Nicholas K. Akins	
		Nicholas K. Akins	
		Chief Executive Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-K of American Electric Power Company, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Julia A. Sloat	
		Julia A. Sloat	
		Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-K of AEP Transmission Company, LLC;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Julia A. Sloat	
		Julia A. Sloat	
		Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-K of AEP Texas Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Julia A. Sloat	
		Julia A. Sloat	
		Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-K of Appalachian Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Julia A. Sloat	
		Julia A. Sloat	
		Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-K of Indiana Michigan Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Julia A. Sloat	
		Julia A. Sloat	
		Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-K of Ohio Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Julia A. Sloat	
		Julia A. Sloat	
		Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-K of Public Service Company of Oklahoma;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Julia A. Sloat	
		Julia A. Sloat	
		Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-K of Southwestern Electric Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2021	By:           
 	/s/ Julia A. Sloat	
		Julia A. Sloat	
		Chief Financial Officer	

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of American Electric Power Company, Inc. (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of AEP Transmission Company, LLC (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to AEP Transmission Company, LLC and will be retained by AEP Transmission Company, LLC and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of AEP Texas Inc. (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to AEP Texas Inc. and will be retained by AEP Texas Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of Appalachian Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company and will be retained by Appalachian Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of Indiana Michigan Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company and will be retained by Indiana Michigan Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of Ohio Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to Ohio Power Company and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of Public Service Company of Oklahoma (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma and will be retained by Public Service Company of Oklahoma and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of Southwestern Electric Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of American Electric Power Company, Inc. (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of AEP Transmission Company, LLC (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to AEP Transmission Company, LLC and will be retained by AEP Transmission Company, LLC and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of AEP Texas Inc. (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to AEP Texas Inc. and will be retained by AEP Texas Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of Appalachian Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company and will be retained by Appalachian Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of Indiana Michigan Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company and will be retained by Indiana Michigan Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of Ohio Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to Ohio Power Company and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of Public Service Company of Oklahoma (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma and will be retained by Public Service Company of Oklahoma and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Annual Report of Southwestern Electric Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

February 25, 2021

A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 95

MINE SAFETY INFORMATION

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of Dolet Hills Lignite Company (DHLC), a wholly-owned lignite mining subsidiary of SWEPCo, is subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. DHLC received the following notices of violation and proposed assessments under the Mine Act for the quarter-ended December 31, 2020:

Number of Citations for S&S Violations of Mandatory Health or Safety Standards under 104 *	—	
Number of Orders Issued under 104(b) *	—	
Number of Citations and Orders for Unwarrantable Failure to Comply with Mandatory Health or Safety Standards under 104(d) *	—	
Number of Flagrant Violations under 110(b)(2) *	—	
Number of Imminent Danger Orders Issued under 107(a)	—	
Total Dollar Value of Proposed Assessments **	$	— 		
Number of Mining-related Fatalities	—	

* References to sections under the Mine Act.
**    DHLC received no citations during the fourth quarter of 2020. There were no proposed assessments received this quarter.

There are currently no legal actions pending before the Federal Mine Safety and Health Review Commission.