UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 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	

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 registrants were 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 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 H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

						
	Number of shares
of common stock
outstanding of the
Registrants as of	
	October 22, 2020	
 	 	
American Electric Power Company, Inc.	496,386,252 		
 	($6.50 par value)	
AEP Texas Inc.	100 		
	($0.01 par value)	
AEP Transmission Company, LLC (a)	NA	
		
Appalachian Power Company	13,499,500 		
 	(no par value)	
Indiana Michigan Power Company	1,400,000 		
 	(no par value)	
Ohio Power Company	27,952,473 		
 	(no par value)	
Public Service Company of Oklahoma	9,013,000 		
 	($15 par value)	
Southwestern Electric Power Company	3,680 		
 	($18 par value)	

(a)100% interest is held by AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of American Electric Power Company, Inc.
NA    Not applicable.

															
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES	
INDEX OF QUARTERLY REPORTS ON FORM 10-Q	
September 30, 2020	
 	 			 	
 	 			Page	
 	 			Number	
Glossary of Terms	i	
 	 			 	
Forward-Looking Information	v	
 	 			 	
Part I. FINANCIAL INFORMATION	 	
 	 			 	
 	Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Controls and Procedures:		
 	 			 	
American Electric Power Company, Inc. and Subsidiary Companies:	 	
 	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1	
 	Condensed Consolidated Financial Statements	50	
 	 			 	
AEP Texas Inc. and Subsidiaries:		
	Management’s Narrative Discussion and Analysis of Results of Operations	57	
	Condensed Consolidated Financial Statements	62	
					
AEP Transmission Company, LLC and Subsidiaries:	 	
 	Management’s Narrative Discussion and Analysis of Results of Operations	69	
 	Condensed Consolidated Financial Statements	71	
					
Appalachian Power Company and Subsidiaries:	 	
 	Management’s Narrative Discussion and Analysis of Results of Operations	77	
 	Condensed Consolidated Financial Statements	82	
 	 			 	
Indiana Michigan Power Company and Subsidiaries:	 	
 	Management’s Narrative Discussion and Analysis of Results of Operations	89	
 	Condensed Consolidated Financial Statements	94	
 	 			 	
Ohio Power Company and Subsidiaries:	 	
 	Management’s Narrative Discussion and Analysis of Results of Operations	101	
 	Condensed Consolidated Financial Statements	106	
 	 			 	
Public Service Company of Oklahoma:	 	
 	Management’s Narrative Discussion and Analysis of Results of Operations	113	
 	Condensed Financial Statements	117	
 	 			 	
Southwestern Electric Power Company Consolidated:	 	
 	Management’s Narrative Discussion and Analysis of Results of Operations	124	
 	Condensed Consolidated Financial Statements	128	
 	 			 	
Index of Condensed Notes to Condensed Financial Statements of Registrants	134	
 	 			 	
Controls and Procedures	224	

															
Part II.  OTHER INFORMATION	 	
 	 	 	 	 	
 	Item 1.	  Legal Proceedings	225	
 	Item 1A.	  Risk Factors	225	
 	Item 2.	  Unregistered Sales of Equity Securities and Use of Proceeds	227	
	Item 3.	  Defaults Upon Senior Securities	227	
 	Item 4.	  Mine Safety Disclosures	227	
 	Item 5.	  Other Information	227	
 	Item 6.	  Exhibits	228	
 	 	 	 	 	
SIGNATURE	 	 	230	

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

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 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 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.	
AFUDC		Allowance for Equity Funds Used During Construction.	
AGR		AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.	
AMI		Advanced Metering Infrastructure.	
AOCI	 	Accumulated Other Comprehensive Income.	
APCo	 	Appalachian Power Company, an AEP electric utility subsidiary.	
Appalachian Consumer Rate Relief Funding		Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.	
APSC		Arkansas Public Service Commission.	
ARAM		Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for rate-making purposes.	
ARO		Asset Retirement Obligations.	
	
ASU		Accounting Standards Update.	
CAA		Clean Air Act.	
Cardinal Operating 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.	
Cook Plant	 	Donald C. Cook Nuclear Plant, a two-unit, 2,288 MW nuclear plant owned by I&M.	
COVID-19		Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.	
CSAPR		Cross-State Air Pollution Rule.	
CWA		Clean Water Act.	
CWIP	 	Construction Work in Progress.	
i

									
Term	 	Meaning	
 	 	 	
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. DHLC is a non-consolidated VIE of SWEPCo.	
DIR		Distribution Investment Rider.	
EIS		Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.	
ENEC		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.	
	
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.	
FASB	 	Financial Accounting Standards Board.	
Federal EPA		United States Environmental Protection Agency.	
FERC	 	Federal Energy Regulatory Commission.	
FGD	 	Flue Gas Desulfurization or scrubbers.	
FIP		Federal Implementation Plan.	
FTR	 	Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.	
GAAP	 	Accounting Principles Generally Accepted in the United States of America.	
Global Settlement		In February 2017, the PUCO approved a settlement agreement filed by OPCo in December 2016 which resolved all remaining open issues on remand from the Supreme Court of Ohio in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings. It also resolved all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.	
I&M	 	Indiana Michigan Power Company, an AEP electric utility subsidiary.	
IRS	 	Internal Revenue Service.	
IURC		Indiana Utility Regulatory Commission.	
KGPCo		Kingsport Power Company, an AEP electric utility subsidiary.	
KPCo	 	Kentucky Power Company, an AEP electric utility subsidiary.	
	
KPSC		Kentucky Public Service Commission.	
KWh		Kilowatt-hour.	
LPSC	 	Louisiana Public Service Commission.	
MATS		Mercury and Air Toxic Standards.	
MISO	 	Midcontinent Independent System Operator.	
MMBtu	 	Million British Thermal Units.	
MPSC		Michigan Public Service Commission.	
MTM	 	Mark-to-Market.	
MW	 	Megawatt.	
MWh	 	Megawatt-hour.	
NAAQS		National Ambient Air Quality Standards.	
Nonutility Money Pool	 	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.	
North Central Wind Energy Facilities		A joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,485 MWs of wind generation.	
ii

									
Term	 	Meaning	
 	 	 	
NO2		Nitrogen dioxide.	
NOx		Nitrogen oxide.	
NPDES		National Pollutant Discharge Elimination System.	
NSR	 	New Source Review.	
OCC	 	Corporation Commission of the State of Oklahoma.	
	
Oklaunion Power Station		A single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant is jointly-owned by AEP Texas, PSO and certain nonaffiliated entities.	
OPCo	 	Ohio Power Company, an AEP electric utility subsidiary.	
OPEB	 	Other Postretirement Benefits.	
	
OTC	 	Over-the-counter.	
OVEC	 	Ohio Valley Electric Corporation, which is 43.47% owned by AEP.	
Parent		American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.	
PATH-WV		PATH West Virginia Transmission Company, LLC, a joint venture owned 50% by FirstEnergy and 50% by AEP.	
PJM	 	Pennsylvania – New Jersey – Maryland regional transmission organization.	
PM	 	Particulate Matter.	
PPA		Purchase Power and Sale Agreement.	
PSO	 	Public Service Company of Oklahoma, an AEP electric utility subsidiary.	
PTC		Production Tax Credits.	
PUCO	 	Public Utilities Commission of Ohio.	
PUCT	 	Public Utility Commission of Texas.	
Racine		A generation plant consisting of two hydroelectric generating units totaling 48 MWs located in Racine, Ohio and owned by AGR.	
Reference Rate Reform		The global transition away from referencing the London Interbank Offered Rate and other interbank offered rates, and toward new reference rates that are more reliable and robust.	
Registrant Subsidiaries	 	AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.	
Registrants		SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.	
Restoration Funding		AEP Texas Restoration Funding LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey.	
Risk Management Contracts	 	Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.	
Rockport Plant		A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.	
ROE		Return on Equity.	
RPM		Reliability Pricing Model.	
RTO	 	Regional Transmission Organization, responsible for moving electricity over large interstate areas.	
Sabine	 	Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo.	
Santa Rita East		Santa Rita East Wind Holdings, LLC, a consolidated VIE whose sole purpose is to own and operate a 302.4 MW wind generation facility in west Texas in which AEP owns a 75% interest.	
SEC		United States Securities and Exchange Commission.	
Sempra Renewables LLC		Sempra Renewables LLC, acquired in April 2019, consists of 724 MWs of wind generation and battery assets in the United States.	
SIP		State Implementation Plan.	
iii

									
Term	 	Meaning	
 	 	 	
SNF	 	Spent Nuclear Fuel.	
SO2	 	Sulfur dioxide.	
SPP	 	Southwest Power Pool regional transmission organization.	
	
State Transcos		AEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP’s existing utility operating companies.	
SWEPCo	 	Southwestern Electric Power Company, an AEP electric utility subsidiary.	
Tax Reform		On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.	

Transition Funding	 	AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated VIEs formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.	
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 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.	
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.	
iv

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

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

						
•	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.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 2019 Annual Report and in Part II of this report.

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

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

EXECUTIVE OVERVIEW

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 could reduce future demand for energy, particularly from commercial and industrial customers. Although AEP cannot predict the severity or duration of the impact of the COVID-19 pandemic, AEP currently anticipates a 2.7% reduction in weather-normalized retail sales volume in 2020 as compared to the prior year. For the nine months ended September 30, 2020, AEP experienced a reduction in weather-normalized retail sales volume of 3.0% as compared to the same period in the prior year primarily driven by a 7.0% decrease in the industrial customer class and a 4.9% decrease in the commercial customer class offset by an increase in demand of 2.6% from the residential customer class. The reduction in weather-normalized retail sales volume of 3.0% did not result in a significant decrease in the corresponding retail margins for the nine months ended 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 quarter of 2020, certain state regulators began to lift restrictions on disconnects. As of September 30, 2020, AEP resumed disconnections in its regulated jurisdictions with the exception of Virginia, West Virginia, Kentucky, Arkansas, Louisiana and Tennessee. AEP’s electric operating companies continue to work with regulators and stakeholders in these states and management currently anticipates resuming customary disconnection practices in the fourth quarter of 2020. 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. During the third quarter of 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. However, as disconnect moratoriums ended or are approaching their end dates, AEP is proactively engaging with customers to collect payments or establish payment arrangements for outstanding balances. As of September 30, 2020, AEP currently does not expect the deterioration in 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.

1

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 September 30, 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, receivables would no longer be purchased by the bank conduits and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity.

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 initial COVID-19 orders with the exception of 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 September 30, 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 September 30, 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 the first nine months of 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. In addition, during the first nine months of 2020, AEP issued approximately $4.0 billion in long-term debt. As of September 30, 2020, AEP’s available liquidity was $3.8 billion. Management believes the Registrants have adequate liquidity under existing credit facilities. In the first quarter of 2020, AEP shifted capital expenditures of $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 Alternative Minimum Tax (AMT) Credit Refund, (b) a 5-year net operating losses (NOL) carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. In May 2020, the House passed the "Health and Economic Recovery Omnibus Emergency Solutions Act" (HEROES Act) pending decision by the Senate. If enacted, the HEROES Act would disallow NOL carrybacks to any tax year beginning before January 1, 2018.  Pursuant to the CARES Act, AEP, APCo and OPCo requested and in July received a $20 million, $7 million and $9 million, respectively, refund of AMT credit. 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 an 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 $52 million, recorded discretely, primarily at the Generation & Marketing segment. On October 1, 2020, after AEP filed its request with the IRS, the House passed a revised version of the HEROES Act; which similar to the original legislation would disallow NOL carryback to years prior to 2018. Management will continue to monitor the potential impact of this legislation. The Registrants are currently deferring 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 September 30, 2020, the Registrants have deferred $32 million of the employer share of payroll taxes and anticipate to defer approximately $50 million by December 31, 2020.
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The Registrants are taking 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 September 30, 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 third quarter of 2020 decreased by 2.6% from the third quarter of 2019. Weather-normalized residential sales increased by 3.8% in the third quarter of 2020 from the third quarter of 2019. AEP’s third quarter 2020 industrial sales volumes decreased by 7.8% compared to the third quarter of 2019. The decline in industrial sales was spread across many industries. Weather-normalized commercial sales decreased 4.6% in the third quarter of 2020 from the third quarter of 2019.

AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 2020 decreased by 3.0% compared to the nine months ended September 30, 2019. Weather-normalized residential sales increased by 2.6% for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019. AEP’s industrial sales volumes for the nine months ended September 30, 2020 decreased 7.0% compared to the nine months ended September 30, 2019. The decline in industrial sales was spread across many industries. Weather-normalized commercial sales decreased 4.9% for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019.

As a result of the impact of COVID-19, AEP revised its forecast for 2020 weather-normalized retail sales volumes in April 2020 and September 2020 from the forecast presented in the 2019 10-K. In 2020, AEP currently anticipates weather-normalized retail sales volumes will decrease by 2.7%. AEP expects industrial class sales volumes to decrease by 6.5% in 2020, while weather-normalized residential sales volumes are projected to increase by 3.1%. Finally, AEP currently projects weather-normalized commercial sales volumes to decrease by 4.8%.

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(a)Percentage change for the year ended December 31, 2019 as compared to the year ended December 31, 2018.
(b)As presented in the 2019 AEP 10-K: Forecasted percentage change for the year ending December 31, 2020 compared to the year ended December 31, 2019.
(c)Revised for the impact of COVID-19 in April 2020: Forecasted percentage change for the year ending December 31, 2020 compared to the year ended December 31, 2019.
(d)Revised for the impact of COVID-19 in September 2020: Forecasted percentage change for the year ending December 31, 2020 compared to the year ended December 31, 2019.

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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 deems 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. In July 2020, a certain intervenor filed testimony asserting that APCo had a revenue surplus of $23 million for its filed rate year based upon the intervenor’s recommended ROE of 8.75%. In addition, this intervenor submitted corrected testimony contending APCo’s earned return for the Triennial period was 11.12%, which equates to a potential refund to customers of $34 million. See “2017-2019 Virginia Triennial Review” section of Note 4 for a full listing of proposed adjustments and disallowances by intervenors. In August and September 2020, the Virginia staff filed testimony supporting an annual APCo Virginia jurisdictional revenue deficiency of $17 million based upon an ROE of 8.73%. However, Virginia staff contends APCo’s earned return for the triennial period was 9.55%, which is above the 9.42% midpoint of APCo’s authorized ROE range. Based on Virginia law, a Virginia SCC order finding an earned ROE above the midpoint would prevent APCo from receiving a prospective increase in Virginia retail rates. In addition, the staff recommended that APCo: (a) reverse the pretax Virginia jurisdictional share of the $93 million expense recorded in December 2019 for its retired coal-fired generation assets and instead amortize the retired assets over a 10-year period beginning in 2015, (b) implement 2017 depreciation study rates effective January 2018 which would increase depreciation expense by $13 million and $15 million in 2018 and 2019, respectively, (c) implement 2019 depreciation study rates effective January 2020 which would increase depreciation expense by $18 million annually starting January 1, 2020 and (d) remove $9 million of major storm expenses and $12 million of coal combustion by-product expenses from the requested annual increase in base rates. APCo expects to receive an order in November 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 September 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. SWEPCo is currently evaluating recovery options for the storm damage in its Arkansas jurisdiction. As of September 30, 2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $69 million ($67 million of which has been
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deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $31 million ($30 million related to the Louisiana jurisdiction).

•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 scheduled for December 2020. As of September 30, 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 including lost shared savings revenues of $26 million annually and renewable mandates no later than 2020 and after 2026, respectively.  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. 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 through 2020 or incurs significant costs defending against the class action lawsuit, 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.

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.

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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		77.4 		(b)		9.7%		March 2020	
AEP Texas		Texas		(40.0)				9.4%		June 2020	

(a)In January 2020, the MPSC issued an order approving a stipulation and settlement agreement. See “2019 Michigan Base Rate Case” section of Note 4 Rate Matters in the 2019 Annual Report for additional information.
(b)Will be phased-in through an increase in base rates which 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. A compliance filing will be made in January 2021 to adjust the final rate increase to reflect the lower of I&Ms actual or IURC-approved Indiana jurisdictional electric plant in service balance as of December 31, 2020. The order rejected I&M’s proposed re-allocation of capacity costs related to the loss of a significant FERC wholesale contract, which will negatively impact I&M’s annual pretax earnings by approximately $20 million starting June 2020.

Pending Base Rate Case Proceedings

											Commission Staff/	
				Filing		Requested Revenue			Requested		Intervenor Range of	
Company		Jurisdiction		Date		Requirement Increase			ROE		Recommended ROE	
						(in millions)						
APCo		Virginia		March 2020		$	64.9 				9.9%		8.73% - 8.75%	
OPCo		Ohio		June 2020		42.3 				10.15%		(a)	
KPCo		Kentucky		June 2020		65.0 				10%		8.93% - 9.25%	
SWEPCo		Texas		October 2020		105.0 		(b)		10.35%		(a)	

(a)Awaiting procedural schedule.
(b)The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments.

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.

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As of September 30, 2020, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,520 MWs of contracted renewable generation projects in-service.  In addition, as of September 30, 2020, these subsidiaries had approximately 140 MWs of renewable generation projects under construction with total estimated capital costs of $243 million related to these projects.

Regulated Renewable Generation Facilities

In July 2019, PSO and SWEPCo submitted filings before their respective commissions for the approval to acquire the North Central Wind Energy Facilities, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion.  PSO will own 45.5% and SWEPCo will own 54.5% of 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 satisfies 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. The 199 MW wind facility is targeted to be placed in-service and acquired in March 2021. The 287 MW wind facility is targeted to be placed in-service and acquired in December 2021 and the 999 MW wind facility is targeted to be placed in-service and acquired between December 2021 and April 2022. All three wind facilities are expected to satisfy the Continuity Safe Harbor.

In February 2020, the OCC approved PSO’s settlement agreement. In May 2020, the APSC approved the settlement agreement as filed, with the exception that SWEPCo use its formula rate rider to recover its costs rather than the requested rider. Also in May 2020, the LPSC approved the settlement agreement as filed. Both the APSC and LPSC approved the flex-up option, agreeing to acquire the Texas portion, which the PUCT denied in July 2020. Having regulatory approval and the IRS extension of the “Continuity Safe Harbor,” PSO and SWEPCo are proceeding with the full 1,485 MW development of these three projects.

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. The table below shows the net book value of each plant, including CWIP and materials and supplies, before cost of removal of the remaining plants included in the study.

Owner		Plant Name		Units		State		Net Book Value as of September 30, 2020		Net Maximum
Capacity (MWs)		Year Plant or First Unit Commissioned	
								(in millions)					
AGR		Racine		2		OH		$	44.7 			48 			1982	
I&M		Berrien Springs		12		MI		6.2 			6 			1908	
I&M		Buchanan		10		MI		4.3 			3 			1919	
I&M		Constantine		4		MI		2.3 			1 			1921	
I&M		Elkhart		3		IN		5.2 			3 			1913	
I&M		Mottville		4		MI		2.7 			2 			1923	
I&M		Twin Branch Hydro		8		IN		5.7 			5 			1904	
		Total		 		 		$	71.1 			68 			 	

If management decides to proceed with the sale of these plants, FERC approval would be required. In addition, for all plants, except for Racine, state commission approval would be required. Management currently estimates that any potential sale agreements for these plants would not be entered into until late 2020 at the earliest. There is no assurance that management will be able to sell any of these plants.
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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 $153 million, including CWIP and materials and supplies, before cost of removal.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the Lignite Mining Agreement, DHLC bills SWEPCo its proportionate share of incurred lignite extraction and associated mining-related costs as fuel is delivered. As of September 30, 2020, DHLC has unbilled lignite inventory and fixed costs of $36 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. In 2009, SWEPCo acquired interests in Oxbow, which owns mineral rights and leases land. Under a Joint Operating Agreement pertaining to the Oxbow mineral rights and land leases, Oxbow bills SWEPCo its proportionate share of incurred costs. As of September 30, 2020, Oxbow has unbilled fixed costs of $10 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. DHLC and Oxbow have billed SWEPCo $111 million for lignite deliveries from April 2020 through September 2020, which primarily includes accelerated depreciation and amortization of fixed costs. 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.

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%).
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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.

LITIGATION

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

Rockport Plant Litigation

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

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 was filed in October 2020. All deadlines, including discovery, are stayed, pending resolution of the motion. See “Modification of the NSR Litigation Consent Decree” section below for additional information.

Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management cannot determine a range of potential losses that is reasonably possible of occurring.

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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.  In July 2020, plaintiffs amended the complaint to add three new patents. The amended complaint seeks injunctive relief and damages.  The case is scheduled for trial in January 2023. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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 are 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. 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, 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.

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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 September 30, 2020, the AEP System had generating capacity of approximately 24,300 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 $500 million to $1 billion through 2026.

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 is currently reviewing the existing standards for PM, last revised in 2012, and ozone, last revised in 2015. A proposed rule to retain the existing PM standards was released in April 2020. A proposed rule to retain the existing standards for ozone was released in August 2020.

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. Management supports the intrastate trading program as a compliance alternative to source-specific controls.
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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.

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.

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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).

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

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

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. Management continues to actively monitor these rulemaking activities.

AEP has taken action to reduce and offset CO2 emissions from its generating fleet. AEP expects CO2 emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions.  In April 2020, Virginia enacted clean energy legislation to allow the state to participate in the Regional Greenhouse Gas Initiative, require the retirement of all fossil-fueled generation by 2045 and require 100% renewable energy to be provided to Virginia customers by 2050. Management is taking steps to comply with these requirements, including increasing wind and solar installations, purchasing renewable power and broadening AEP System’s portfolio of energy efficiency programs.

In September 2019, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. The intermediate goal is a 70% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is to surpass an 80% reduction of CO2 emissions from AEP generating facilities from 2000 levels by 2050. AEP’s total estimated CO2 emissions in 2019 were approximately 58 million metric tons, a 65% reduction from AEP’s 2000 CO2 emissions. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. AEP’s aspirational emissions goal is zero CO2 emissions by 2050. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers.

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Federal and state legislation or regulations that mandate limits on the emission of CO2 could result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force AEP to close some coal-fired facilities, which could possibly lead to impairment of assets.

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, will be the subject of further rulemaking consistent with the court’s decision.

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. 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 deadline for seeking an extension under either option is November 30, 2020.

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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.

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.

Because AEP currently uses surface impoundments and landfills to manage CCR materials at generating facilities, significant costs may be incurred to upgrade or close and replace these existing facilities and conduct any required remedial actions. Management is evaluating various compliance options. 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 may begin recovering these costs through the E-RAC beginning July 1, 2022. APCo is permitted to record carrying costs on the unrecovered balance of closure costs at a weighted average cost of capital approved by the Virginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered from Virginia jurisdictional customers through the E-RAC.

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 already have been closed in place in accordance with state law programs. Management will continue to participate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units.

Clean Water Act Regulations

In 2014, the 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
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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 is assessing 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.

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 12 (NWP 12), which provides standard conditions governing linear utility projects in streams, wetlands and other waters of the United States having minimal adverse environmental impacts. The Court found that in reissuing NWP 12 in 2017, the Corps failed to comply with Section 7 of the Endangered Species Act (ESA), which requires the Corps to consult with the U.S. Fish and Wildlife Service regarding potential impacts on endangered species. The Court remanded the permit back to the Corps to complete its ESA consultation, and also enjoined the Corps from authorizing any dredge or fill activities under NWP 12 pending completion of the consultation process. The Department of Justice filed a motion to stay the injunction and tailor the remedy imposed by the Court. 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 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 and evaluating other permitting alternatives, 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 has narrowed the focus of NWP 12 to only oil and natural gas pipeline activities. The Corps is proposing 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. Management is currently assessing impacts of the proposal on current and planned projects.
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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

•Competitive generation in ERCOT and PJM.
•Contracted renewable energy investments and management services.
•Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP.

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

The following discussion of AEP’s results of operations by operating segment includes an analysis of Gross Margin, which is a non-GAAP financial measure. Gross Margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation as well as Purchased Electricity for Resale and Amortization of Generation Deferrals as presented in the Registrants 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.
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The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:

	Three Months Ended		Nine Months Ended	
	September 30,		September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Vertically Integrated Utilities	$	393.5 			$	437.6 			$	894.7 			$	917.7 		
Transmission and Distribution Utilities	147.4 			133.7 			403.1 			421.6 		
AEP Transmission Holdco	138.3 			126.1 			370.4 			404.8 		
Generation & Marketing	116.7 			90.0 			211.0 			139.5 		
Corporate and Other	(47.3)			(53.9)			(114.6)			(116.0)		
Earnings Attributable to AEP Common Shareholders	$	748.6 			$	733.5 			$	1,764.6 			$	1,767.6 		

AEP CONSOLIDATED

Third Quarter of 2020 Compared to Third Quarter of 2019

Earnings Attributable to AEP Common Shareholders increased from $734 million in 2019 to $749 million in 2020 to primarily due to:

•Favorable rate proceedings in AEP’s various jurisdictions.
•A planned decrease in Other Operation and Maintenance expenses.
•The recognition of a discrete tax adjustment in 2020 which was attributable to the 5-year net operating loss carryback provision of the CARES Act.

These increases were partially offset by:

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

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Earnings Attributable to AEP Common Shareholders decreased from $1,768 million in 2019 to $1,765 million in 2020 primarily due to:

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

These decreases were partially offset by:

•Favorable rate proceedings in AEP’s various jurisdictions.
•A planned decrease in Other Operation and Maintenance expenses.
•The recognition of a discrete tax adjustment in 2020 which was attributable to the 5-year net operating loss carryback provision of the CARES Act.

AEP’s results of operations by operating segment are discussed below.
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VERTICALLY INTEGRATED UTILITIES

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
 Vertically Integrated Utilities		2020		2019		2020		2019	
 		(in millions)	
Revenues		$	2,434.8 			$	2,645.5 			$	6,753.5 			$	7,172.6 		
Fuel and Purchased Electricity		693.7 			874.2 			1,947.0 			2,430.2 		
	
Gross Margin		1,741.1 			1,771.3 			4,806.5 			4,742.4 		
Other Operation and Maintenance		715.9 			742.9 			2,031.8 			2,117.1 		

Depreciation and Amortization		398.8 			364.3 			1,173.8 			1,079.6 		
Taxes Other Than Income Taxes		121.0 			117.9 			355.6 			347.1 		
Operating Income		505.4 			546.2 			1,245.3 			1,198.6 		

Other Income (Expense)		(0.7)			0.9 			2.3 			4.4 		
Allowance for Equity Funds Used During Construction		15.9 			12.2 			33.1 			38.9 		
Non-Service Cost Components of Net Periodic Benefit Cost		16.9 			17.0 			50.9 			50.8 		
Interest Expense		(140.2)			(140.6)			(426.5)			(422.6)		
Income Before Income Tax Expense (Benefit) and
Equity Earnings		397.3 			435.7 			905.1 			870.1 		
Income Tax Expense (Benefit)		3.8 			(1.9)			10.5 			(48.4)		
Equity Earnings of Unconsolidated Subsidiary		0.7 			0.8 			2.2 			2.3 		
Net Income		394.2 			438.4 			896.8 			920.8 		
Net Income Attributable to Noncontrolling Interests		0.7 			0.8 			2.1 			3.1 		
Earnings Attributable to AEP Common Shareholders		$	393.5 			$	437.6 			$	894.7 			$	917.7 		

Summary of KWh Energy Sales for Vertically Integrated Utilities

		Three Months Ended September 30,		Nine Months Ended 
September 30,	
		2020		2019		2020		2019	
 		(in millions of KWhs)	
Retail:		 		 		 		 	
Residential		9,066 			9,254 			24,304 			24,785 		
Commercial		6,257 			6,840 			16,773 			18,183 		
Industrial		8,161 			9,123 			24,335 			26,533 		
Miscellaneous		595 			641 			1,636 			1,734 		
Total Retail		24,079 			25,858 			67,048 			71,235 		
									
Wholesale (a)		4,574 			5,864 			13,116 			16,494 		
									
Total KWhs		28,653 			31,722 			80,164 			87,729 		

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

21

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

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities

		Three Months Ended September 30,		Nine Months Ended 
September 30,	
		2020		2019		2020		2019	
 		(in degree days)	
Eastern Region		 		 		 		 	
Actual – Heating (a)		3 			— 			1,456 			1,670 		
Normal – Heating (b)		4 			5 			1,752 			1,742 		
									
Actual – Cooling (c)		867 			937 			1,204 			1,316 		
Normal – Cooling (b)		739 			732 			1,081 			1,070 		
									
Western Region		 		 		 		 	
Actual – Heating (a)		1 			— 			699 			967 		
Normal – Heating (b)		1 			1 			902 			902 		
									
Actual – Cooling (c)		1,291 			1,572 			2,015 			2,234 		
Normal – Cooling (b)		1,416 			1,402 			2,144 			2,129 		

(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.

22

Third Quarter of 2020 Compared to Third Quarter of 2019

Reconciliation of Third Quarter of 2019 to Third Quarter of 2020	
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities	
(in millions)	
 			
Third Quarter of 2019		$	437.6 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		(14.3)		
Margins from Off-system Sales		(5.5)		
Transmission Revenues		(3.1)		
Other Revenues		(7.3)		
Total Change in Gross Margin		(30.2)		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		27.0 		
	
Depreciation and Amortization		(34.5)		
Taxes Other Than Income Taxes		(3.1)		

Other Income		(1.6)		
Allowance for Equity Funds Used During Construction		3.7 		
Non-Service Cost Components of Net Periodic Pension Cost		(0.1)		
Interest Expense		0.4 		
Total Change in Expenses and Other		(8.2)		
 		 	
Income Tax Expense		(5.7)		
Equity Earnings of Unconsolidated Subsidiary		(0.1)		
Net Income Attributable to Noncontrolling Interests		0.1 		
			
Third Quarter of 2020		$	393.5 		

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 $50 million decrease in weather-related usage primarily in the western region and primarily in the residential class.
•A $24 million decrease in weather-normalized margins for wholesale customers, including the loss of a significant wholesale contract at I&M.
•A $4 million decrease in revenue from rate riders at PSO. This decrease was partially offset in other expense items below.
•A $3 million decrease in weather-normalized retail margins driven by a $42 million decrease in the commercial and industrial customer classes partially offset by a $41 million increase in the residential customer class.
These decreases were partially offset by:
•The effect of rate proceedings in AEP’s service territories which included:
•A $38 million increase at I&M primarily due to the Indiana and Michigan base rate cases and an overall increase in revenue from rate riders. This increase was partially offset in other expense items below.
•A $14 million increase at SWEPCo primarily due to a base rate revenue increase in Arkansas.
•A $10 million increase in deferred fuel at APCo and WPCo primarily due to the timing of recoverable PJM expenses. This increase was offset in other expense items below.
•A $5 million increase at APCo and WPCo due to the WVPSC’s approval of the Mitchell Plant surcharge effective January 2020.
23

•Margins from Off-system Sales decreased $6 million due to weaker market prices for energy in the RTOs which caused a decrease in sales volume and margins and the historical merchant portion of WPCo’s Mitchell Plant moving to retail rates beginning in January 2020.
•Other Revenues decreased $7 million primarily due to a decrease at I&M in barging revenues by River Transportation Division (RTD). This decrease was partially offset in Other Operation and Maintenance expenses below.

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

•Other Operation and Maintenance expenses decreased $27 million primarily due to the following:
•A $23 million decrease in distribution expenses primarily related to vegetation management, storms and other distribution expenses.
•A $13 million decrease in plant outage and maintenance expenses primarily at I&M, SWEPCo, PSO and KPCo.
•An $8 million decrease due to the modification of the NSR consent decree impacting I&M and AEGCo in 2019.
•A $4 million decrease in transmission expenses primarily related to RTO fees, NERC activities and station/line inspections.
•A $4 million decrease in customer-related expenses.
These decreases were partially offset by:
•A $30 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $35 million primarily due to a higher depreciable base and increased depreciation rates approved at I&M and SWEPCo. This increase was partially offset in Retail Margins above.
•Income Tax Expense increased $6 million primarily due to a decrease in amortization of Excess ADIT, partially offset by a decrease in pretax book income and an increase in favorable flow-through tax benefits. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.

24

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020	
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities	
(in millions)	
 			
Nine Months Ended September 30, 2019		$	917.7 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		38.5 		
Margins from Off-system Sales		(14.2)		
Transmission Revenues		48.7 		
Other Revenues		(8.9)		
Total Change in Gross Margin		64.1 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		85.3 		
	
Depreciation and Amortization		(94.2)		
Taxes Other Than Income Taxes		(8.5)		

Other Income		(2.1)		
Allowance for Equity Funds Used During Construction		(5.8)		
Non-Service Cost Components of Net Periodic Pension Cost		0.1 		
Interest Expense		(3.9)		
Total Change in Expenses and Other		(29.1)		
 		 	
Income Tax Expense		(58.9)		
Equity Earnings of Unconsolidated Subsidiary		(0.1)		
Net Income Attributable to Noncontrolling Interests		1.0 		
			
Nine Months Ended September 30, 2020		$	894.7 		

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 $39 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 $16 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $15 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 $14 million increase due to the impact of the 2019 WVPSC order which required APCo and WPCo to offset Excess ADIT not subject to normalization requirements against the deferred fuel under-recovery balance in 2019.
•The effect of rate proceedings in AEP’s service territories which included:
•A $72 million increase at I&M primarily due to the Indiana and Michigan base rate cases and an overall increase in revenue from rate riders. This increase was partially offset in other expense items below.
•A $35 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.
•A $10 million increase at APCo and WPCo due to a base rate increase in West Virginia. This increase was partially offset in Depreciation and Amortization expenses below.
•A $6 million increase in municipal and cooperative revenues at SWEPCo primarily due to formula rate true-ups.
25

These increases were partially offset by:
•A $95 million decrease in weather-related usage primarily in the residential class.
•A $47 million decrease in weather-normalized margins for wholesale contracts, including the loss of a significant wholesale contract at I&M.
•A $12 million decrease in weather-normalized retail margins driven by a $93 million decrease in the commercial and industrial classes partially offset by an $85 million increase in the residential customer class.
•A $10 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 $14 million due to weaker market prices for energy in the RTOs which caused a decrease in sales volume and margins and the historical merchant portion of WPCo’s Mitchell Plant moving to retail rates beginning in January 2020.
•Transmission Revenues increased $49 million primarily due to the following:
•A $26 million increase due to continued investment in transmission projects primarily at SWEPCo.
•A $23 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.
•Other Revenues decreased $9 million primarily due to the following:
•A decrease of $14 million at I&M primarily due to a decrease in barging revenues by RTD. This decrease was partially offset in Other Operation and Maintenance expenses below.
This decrease was partially offset by:
•A $3 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 $85 million primarily due to the following:
•A $53 million decrease in plant outage and maintenance expenses primarily at APCo, I&M, WPCo, KPCo and PSO.
•A $22 million decrease in distribution expenses primarily vegetation management and other distribution expenses.
•A $12 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs at SWEPCo and PSO.
•A $10 million decrease in transmission expenses primarily related to RTO fees, NERC activities and station/line inspections.
•An $8 million decrease due to the modification of the NSR consent decree impacting I&M and AEGCo in 2019.
•A $7 million decrease in PJM transmission services including the annual formula rate true-up.
•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 $10 million increase due to storms primarily at KPCo and PSO.
•A $3 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $94 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 $9 million primarily due to the following:
•A $6 million increase in property taxes due to additional investments in utility plant.
•A $3 million increase in state business and occupation taxes at APCo due to the reduction of the revitalization tax credit.
•Allowance for Equity Funds Used During Construction decreased $6 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 increased $4 million primarily due to higher long-term debt balances at APCo.
•Income Tax Expense increased $59 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.
26

TRANSMISSION AND DISTRIBUTION UTILITIES

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
Transmission and Distribution Utilities		2020		2019		2020		2019	
 		(in millions)	
Revenues		$	1,165.3 			$	1,186.6 			$	3,306.7 			$	3,454.3 		
Purchased Electricity		183.8 			210.1 			522.7 			603.5 		
Amortization of Generation Deferrals		— 			8.8 			— 			65.3 		
Gross Margin		981.5 			967.7 			2,784.0 			2,785.5 		
Other Operation and Maintenance		439.1 			405.8 			1,158.2 			1,222.1 		

Depreciation and Amortization		163.5 			209.3 			585.0 			586.4 		
Taxes Other Than Income Taxes		156.4 			151.8 			444.4 			437.2 		
Operating Income		222.5 			200.8 			596.4 			539.8 		
Interest and Investment Income		0.9 			1.1 			2.0 			4.2 		
Carrying Costs Income		0.3 			0.3 			1.3 			0.7 		
	
Allowance for Equity Funds Used During Construction		9.0 			9.8 			23.7 			22.3 		
Non-Service Cost Components of Net Periodic Benefit Cost		7.4 			7.7 			22.1 			22.8 		
Interest Expense		(74.0)			(63.6)			(217.6)			(170.8)		
Income Before Income Tax Expense (Benefit)		166.1 			156.1 			427.9 			419.0 		
Income Tax Expense (Benefit)		18.7 			22.4 			24.8 			(2.6)		
Net Income		147.4 			133.7 			403.1 			421.6 		
Net Income Attributable to Noncontrolling Interests		— 			— 			— 			— 		
Earnings Attributable to AEP Common Shareholders		$	147.4 			$	133.7 			$	403.1 			$	421.6 		

Summary of KWh Energy Sales for Transmission and Distribution Utilities

		Three Months Ended 
September 30,		Nine Months Ended 
September 30,	
		2020		2019		2020		2019	
 		(in millions of KWhs)	
Retail:		 		 		 		 	
Residential		8,277 			8,268 			20,876 			20,614 		
Commercial		6,722 			7,219 			18,154 			19,069 		
Industrial		5,417 			5,857 			16,473 			17,492 		
Miscellaneous		206 			223 			568 			595 		
Total Retail (a)		20,622 			21,567 			56,071 			57,770 		
									
Wholesale (b)		502 			453 			1,347 			1,531 		
									
Total KWhs		21,124 			22,020 			57,418 			59,301 		

(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.
27

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

		Three Months Ended 
September 30,		Nine Months Ended 
September 30,	
		2020		2019		2020		2019	
 		(in degree days)	
Eastern Region		 		 		 		 	
Actual – Heating (a)		2 			— 			1,767 			2,006 		
Normal – Heating (b)		6 			6 			2,086 			2,072 		
									
Actual – Cooling (c)		809 			872 			1,126 			1,176 		
Normal – Cooling (b)		682 			672 			986 			973 		
									
Western Region		 		 		 		 	
Actual – Heating (a)		1 			— 			98 			180 		
Normal – Heating (b)		— 			— 			188 			190 		
									
Actual – Cooling (d)		1,357 			1,587 			2,524 			2,679 		
Normal – Cooling (b)		1,378 			1,368 			2,436 			2,425 		

(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.

28

Third Quarter of 2020 Compared to Third Quarter of 2019

Reconciliation of Third Quarter of 2019 to Third Quarter of 2020	
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities	
(in millions)	
 		 	
Third Quarter of 2019		$	133.7 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		54.8 		
Margins from Off-system Sales		(1.4)		
Transmission Revenues		15.8 		
Other Revenues		(55.4)		
Total Change in Gross Margin		13.8 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(33.3)		
Depreciation and Amortization		45.8 		
Taxes Other Than Income Taxes		(4.6)		
Interest and Investment Income		(0.2)		
	
Allowance for Equity Funds Used During Construction		(0.8)		
Non-Service Cost Components of Net Periodic Benefit Cost		(0.3)		
Interest Expense		(10.4)		
Total Change in Expenses and Other		(3.8)		
 		 	
Income Tax Expense		3.7 		
 		 	
Third Quarter of 2020		$	147.4 		

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 $55 million primarily due to the following:
•A $52 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
•An $18 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.
•A $9 million increase in weather-normalized margins primarily in the residential class and partially offset in the commercial and industrial classes.
•A $6 million increase from interim rate increases driven by increased distribution investment in Texas.
•A $5 million increase in revenues in Ohio associated with the Universal Service Fund (USF). This increase was offset in Other Operation and Maintenance expenses below.
•A $5 million increase due to new base rates implemented in June 2020 in Texas.
•A $3 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.
These increases were partially offset by:
•A $19 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.
•An $11 million decrease in weather-related usage in Texas primarily due to a 14% decrease in cooling degree days.
•A $6 million decrease due to the OVEC PPA Rider which was replaced by the Legacy Generation Resource Rider (LGRR). This decrease was offset in Margins from Off-system Sales and Other Revenues below.
•A $3 million decrease in revenues associated with a vegetation management rider in Ohio. This decrease was offset in Other Operation and Maintenance expenses below.
•A $3 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.
29

•Transmission Revenues increased $16 million primarily due to the following:
•An $11 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $7 million increase in Ohio due to the annual transmission formula rate true-up.
•A $4 million increase primarily due to recovery of increased transmission investment in PJM.
These increases were partially offset by:
•A $7 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease was offset in Other Revenues below.
•Other Revenues decreased $55 million primarily due to the following:
•A $68 million decrease in securitization revenues due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This increase was offset in Depreciation and Amortization expenses and Interest Expense below.
This decrease was partially offset by:
•An $8 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 partially 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 increased $33 million primarily due to the following:
•A $50 million increase in transmission expenses primarily due to an increase in PJM and ERCOT expenses. This increase was offset in Gross Margin above.
•A $5 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.
These decreases were partially offset by:
•A $16 million decrease in distribution expenses. This decrease was partially offset in Gross Margins above.
•Depreciation and Amortization expenses decreased $46 million primarily due to the following:
•A $63 million decrease in securitization amortizations in Texas due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This increase was offset in Other Revenues above and Interest Expense below.
This decrease was partially offset by:
•A $9 million increase in Ohio recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•A $5 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•Taxes Other Than Income Taxes increased $5 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•Interest Expense increased $10 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $4 million primarily due to an increase in amortization of Excess ADIT, partially offset by an increase in pretax book income. This decrease was partially offset in Gross Margins and Other Operation and Maintenance Expenses above.
30

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020	
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities	
(in millions)	
 			
Nine Months Ended September 30, 2019		$	421.6 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		8.7 		
Margins from Off-system Sales		(17.3)		
Transmission Revenues		31.7 		
Other Revenues		(24.6)		
Total Change in Gross Margin		(1.5)		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		63.9 		
Depreciation and Amortization		1.4 		
Taxes Other Than Income Taxes		(7.2)		
Interest and Investment Income		(2.2)		
Carrying Costs Income		0.6 		
Allowance for Equity Funds Used During Construction		1.4 		
Non-Service Cost Components of Net Periodic Benefit Cost		(0.7)		
Interest Expense		(46.8)		
Total Change in Expenses and Other		10.4 		
 		 	
Income Tax Expense		(27.4)		
 		 	
Nine Months Ended September 30, 2020		$	403.1 		

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

•Retail Margins increased $9 million primarily due to the following:
•A $74 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
•A $48 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.
•A $15 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.
•A $15 million increase in revenues in Ohio associated with the USF. This increase was offset in Other Operation and Maintenance expenses below.
•An $8 million increase in weather-normalized margins primarily in the residential class and partially offset in the industrial and commercial classes.
•A $7 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $7 million increase from interim rate increases driven by increased distribution investment in Texas.
•A $7 million increase due to new base rates implemented in June 2020 in Texas.
•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 $25 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.
•A $23 million decrease in Ohio Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below.
31

•A $21 million decrease due to the OVEC PPA Rider which was replaced by the LGRR. This decrease was offset in Margins from Off-system Sales and Other Revenues below.
•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 $15 million decrease in weather-related usage in Texas primarily due to a 6% decrease in cooling degree days and a 46% decrease in heating degree days.
•A $9 million decrease in revenues associated with a vegetation management rider in Ohio. This decrease was offset in Other Operation and Maintenance expenses below.
•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Other Operation and Maintenance expenses below.
•A $4 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease was offset in Other Revenues below.
•Margins from Off-system Sales decreased $17 million primarily due to the following:
•A $20 million decrease in Texas primarily due to lower Oklaunion Power Station PPA revenues. This decrease was offset in Other Operation and Maintenance expenses below.
•A $12 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:
•An $18 million increase in Ohio due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above.
•Transmission Revenues increased $32 million primarily due to the following:
•A $30 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 $7 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 $25 million primarily due to the following:
•A $49 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 $12 million increase in Ohio primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.
•An $11 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 $64 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 for Off-System Sales above.
•A $15 million decrease in distribution expenses primarily due to vegetation management. This decrease was partially offset in Retail Margins above.
•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.

32

These decreases were partially offset by:
•A $41 million increase in transmission expenses primarily due to a $68 million increase in recoverable PJM and ERCOT expenses partially offset by a $28 million decrease related to the annual PJM transmission formula rate true-up. This increase was offset in Gross Margin above.
•A $15 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
•Depreciation and Amortization expenses decreased $1 million primarily due to the following:
•A $43 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 $27 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•A $16 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 $7 million increase in amortizations primarily due to capitalized software.
•A $6 million increase in recoverable smart grid expense in Ohio. This increase was offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $7 million primarily due to the following:
•A $13 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 $4 million decrease in excise taxes due to lower demand in 2020 in Ohio. This decrease was offset in Retail Margins above.
•Interest Expense increased $47 million primarily due to the following:
•A $24 million increase due to the 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 $21 million increase due to higher long-term debt balances.
•A $7 million increase due to due to a decrease in the debt component of AFUDC.
These increases were partially offset by:
•A $5 million decrease due to lower short-term debt balances.
•Income Tax Expense increased $27 million primarily due to 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 partially offset by current year amortization of Excess ADIT and an increase in favorable AFUDC Equity tax benefit. This increase was partially offset in Gross Margins and Other Operation and Maintenance Expenses above.
33

AEP TRANSMISSION HOLDCO

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
AEP Transmission Holdco		2020		2019		2020		2019	
 		(in millions)	
Transmission Revenues		$	317.9 			$	273.0 			$	877.8 			$	808.3 		
Other Operation and Maintenance		30.1 			31.8 			85.9 			77.0 		
Depreciation and Amortization		63.6 			47.3 			182.8 			133.7 		
Taxes Other Than Income Taxes		53.8 			44.3 			157.5 			130.4 		
Operating Income		170.4 			149.6 			451.6 			467.2 		
Interest and Investment Income		0.2 			0.8 			2.6 			2.3 		

Allowance for Equity Funds Used During Construction		20.3 			21.0 			54.9 			61.1 		
Non-Service Cost Components of Net Periodic Benefit Cost		0.5 			0.7 			1.5 			2.0 		
Interest Expense		(34.0)			(27.8)			(99.0)			(73.8)		
Income Before Income Tax Expense and Equity Earnings		157.4 			144.3 			411.6 			458.8 		
Income Tax Expense		38.2 			35.4 			101.3 			105.7 		
Equity Earnings of Unconsolidated Subsidiary		20.1 			18.1 			62.8 			54.5 		
Net Income		139.3 			127.0 			373.1 			407.6 		
Net Income Attributable to Noncontrolling Interests		1.0 			0.9 			2.7 			2.8 		
Earnings Attributable to AEP Common Shareholders		$	138.3 			$	126.1 			$	370.4 			$	404.8 		

Summary of Investment in Transmission Assets for AEP Transmission Holdco

		September 30,	
		2020		2019	
		(in millions)	
Plant in Service		$	9,644.6 			$	7,796.9 		
Construction Work in Progress		1,732.5 			1,903.4 		
Accumulated Depreciation and Amortization		553.1 			383.7 		
Total Transmission Property, Net		$	10,824.0 			$	9,316.6 		
34

Third Quarter of 2020 Compared to Third Quarter of 2019
 
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)

Third Quarter of 2019		$	126.1 		
			
Changes in Transmission Revenues:			
Transmission Revenues		44.9 		
Total Change in Transmission Revenues		44.9 		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		1.7 		
Depreciation and Amortization		(16.3)		
Taxes Other Than Income Taxes		(9.5)		
Interest and Investment Income		(0.6)		
	
Allowance for Equity Funds Used During Construction		(0.7)		
Non-Service Cost Components of Net Periodic Pension Cost		(0.2)		
Interest Expense		(6.2)		
Total Change in Expenses and Other		(31.8)		
			
Income Tax Expense		(2.8)		
Equity Earnings of Unconsolidated Subsidiary		2.0 		
Net Income Attributable to Noncontrolling Interests		(0.1)		
			
Third Quarter of 2020		$	138.3 		

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

•Transmission Revenues increased $45 million primarily due to continued investment in transmission assets.

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

•Depreciation and Amortization expenses increased $16 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $10 million primarily due to higher property taxes as a result of increased transmission investment.
•Interest Expense increased $6 million primarily due to higher long-term debt balances.
35

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
 
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)

Nine Months Ended September 30, 2019		$	404.8 		
			
Changes in Transmission Revenues:			
Transmission Revenues		69.5 		
Total Change in Transmission Revenues		69.5 		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		(8.9)		
Depreciation and Amortization		(49.1)		
Taxes Other Than Income Taxes		(27.1)		
Interest and Investment Income		0.3 		
	
Allowance for Equity Funds Used During Construction		(6.2)		
Non-Service Cost Components of Net Periodic Pension Cost		(0.5)		
Interest Expense		(25.2)		
Total Change in Expenses and Other		(116.7)		
			
Income Tax Expense		4.4 		
Equity Earnings of Unconsolidated Subsidiary		8.3 		
Net Income Attributable to Noncontrolling Interests		0.1 		
			
Nine Months Ended September 30, 2020		$	370.4 		

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

•Transmission Revenues increased $70 million primarily due to the following:
•A $149 million increase due to continued investment in transmission assets.
This increase was partially offset by the following:
•A $62 million decrease as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant subsidiaries.
•A $17 million decrease as a result of the non-affiliated annual transmission formula rate true-up.

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

•Other Operation and Maintenance expenses increased $9 million primarily due to the following:
•A $5 million increase in rent expense.
•A $3 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $49 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $27 million primarily due to higher property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During Construction decreased $6 million primarily due to the following:
•A $12 million decrease driven by the favorable impact of a FERC settlement agreement recorded in 2019.
•An $8 million decrease due to lower CWIP.
These decreases were partially offset by:
•A $13 million increase driven by FERC audit findings recorded in 2019.
•Interest Expense increased $25 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $4 million primarily due to lower pretax book income, partially offset by the recognition of a discrete tax adjustment in 2019.
•Equity Earnings of Unconsolidated Subsidiary increased $8 million primarily due to higher pretax equity earnings at PATH-WV and ETT.
36

GENERATION & MARKETING

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
Generation & Marketing		2020		2019		2020		2019	
 		(in millions)	
Revenues		$	490.0 			$	533.7 			$	1,305.5 			$	1,428.2 		
Fuel, Purchased Electricity and Other		391.6 			403.8 			1,050.4 			1,117.8 		
	
Gross Margin		98.4 			129.9 			255.1 			310.4 		
Other Operation and Maintenance		27.2 			44.0 			85.1 			158.0 		

Depreciation and Amortization		18.5 			20.6 			54.1 			49.1 		
Taxes Other Than Income Taxes		3.3 			4.4 			10.4 			11.8 		
Operating Income		49.4 			60.9 			105.5 			91.5 		
Interest and Investment Income		0.4 			1.9 			2.6 			6.0 		
	
Non-Service Cost Components of Net Periodic Benefit Cost		3.9 			3.8 			11.6 			11.2 		
Interest Expense		(3.8)			(10.5)			(20.5)			(21.5)		
Income Before Income Tax Benefit and Equity Earnings (Loss)		49.9 			56.1 			99.2 			87.2 		
Income Tax Benefit		(70.9)			(36.4)			(104.3)			(51.8)		
Equity Earnings (Loss) of Unconsolidated Subsidiaries		(6.2)			(3.8)			0.1 			(5.9)		
Net Income		114.6 			88.7 			203.6 			133.1 		
Net Loss Attributable to Noncontrolling Interests		(2.1)			(1.3)			(7.4)			(6.4)		
Earnings Attributable to AEP Common Shareholders		$	116.7 			$	90.0 			$	211.0 			$	139.5 		

Summary of MWhs Generated for Generation & Marketing

		Three Months Ended 
September 30,		Nine Months Ended 
September 30,	
		2020		2019		2020		2019	
 		(in millions of MWhs)	
Fuel Type:		 		 		 		 	
Coal		1 			2 			3 			4 		
Renewables		— 			1 			2 			2 		
	
Total MWhs		1 			3 			5 			6 		
37

Third Quarter of 2020 Compared to Third Quarter of 2019

Reconciliation of Third Quarter of 2019 to Third Quarter of 2020	
Earnings Attributable to AEP Common Shareholders from Generation & Marketing	
(in millions)	
 		 	
Third Quarter of 2019		$	90.0 		
 		 	
Changes in Gross Margin:		 	
Merchant Generation		(24.3)		
Renewable Generation		(4.1)		
Retail, Trading and Marketing		(3.1)		
Total Change in Gross Margin		(31.5)		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		16.8 		

Depreciation and Amortization		2.1 		
Taxes Other Than Income Taxes		1.1 		
Interest and Investment Income		(1.5)		

Non-Service Cost Components of Net Periodic Benefit Cost		0.1 		
Interest Expense		6.7 		
Total Change in Expenses and Other		25.3 		
 		 	
Income Tax Benefit		34.5 		
Equity Earnings (Loss) of Unconsolidated Subsidiaries		(2.4)		
Net Loss Attributable to Noncontrolling Interests		0.8 		
 		 	
Third Quarter of 2020		$	116.7 		

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, purchased electricity and certain cost of service for retail operations were as follows:

•Merchant Generation decreased $24 million primarily due to lower capacity revenues and energy margins in 2020 and the retirement of the Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020.
•Renewable Generation decreased $4 million primarily due to lower wind production.
•Retail, Trading and Marketing decreased $3 million due to lower trading and marketing activity, partially offset by higher retail margins.

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

•Other Operation and Maintenance expenses decreased $17 million primarily due to the following:
•An $11 million decrease due to a gain recorded on the sale of land.
•An $8 million decrease due to the retirement of Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020.
•Interest Expense decreased $7 million due to lower borrowing costs in 2020.
•Income Tax Benefit increased $35 million primarily due to the recognition of a discrete tax adjustment in 2020, which was attributable to the CARES Act offset by a decrease in PTC.

38

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020	
Earnings Attributable to AEP Common Shareholders from Generation & Marketing	
(in millions)	
 		 	
Nine Months Ended September 30, 2019		$	139.5 		
 		 	
Changes in Gross Margin:		 	
Merchant Generation		(78.3)		
Renewable Generation		17.4 		
Retail, Trading and Marketing		5.6 		
Total Change in Gross Margin		(55.3)		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		72.9 		

Depreciation and Amortization		(5.0)		
Taxes Other Than Income Taxes		1.4 		
Interest and Investment Income		(3.4)		
	
Non-Service Cost Components of Net Periodic Benefit Cost		0.4 		
Interest Expense		1.0 		
Total Change in Expenses and Other		67.3 		
 		 	
Income Tax Benefit		52.5 		
Equity Earnings (Loss) of Unconsolidated Subsidiaries		6.0 		
Net Loss Attributable to Noncontrolling Interests		1.0 		
 		 	
Nine Months Ended September 30, 2020		$	211.0 		

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 and Unit 4 in 2020.
•Renewable Generation increased $17 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in-service.
•Retail, Trading and Marketing increased $6 million due to higher trading and marketing activity, partially offset by lower retail margins.

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

•Other Operation and Maintenance expenses decreased $73 million due to the following:
•A $34 million decrease due to the retirement of Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020.
•A $26 million decrease due to a gain recorded on the sale of land.
•A $16 million decrease related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision.
•Depreciation and Amortization expenses increased $5 million due to a higher depreciable base from increased investments in renewable energy sources.
•Interest and Investment Income decreased $3 million due to lower returns on investments.
•Income Tax Benefit increased $53 million primarily due the recognition of a discrete tax adjustment in 2020, which was attributable to the CARES Act and an increase in PTC.
•Equity Earnings (Loss) of Unconsolidated Subsidiaries increased $6 million primarily due to the Sempra Renewables LLC acquisition.
39

CORPORATE AND OTHER

Third Quarter of 2020 Compared to Third Quarter of 2019

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $54 million in 2019 to a loss of $47 million in 2020 primarily due to:

•A $12 million decrease in income tax expense due to a decrease in consolidating tax adjustments.
•A $6 million decrease in interest expense as a result of a decrease in debt outstanding.

These items were partially offset by:

•A $5 million increase in general corporate expenses.
•A $6 million decrease in interest income.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $116 million in 2019 to a loss of $115 million in 2020 primarily due to:

•An $11 million decrease in general corporate expenses.
•A $5 million write-off of an equity investment and related assets in 2019.
•A $2 million decrease in income tax expense due to discrete items recorded in 2020, partially offset by an increase in consolidating tax adjustments.

These items were partially offset by:

•An $8 million decrease in interest income.
•An $8 million increase in interest expense as a result of an increase in debt outstanding.

AEP SYSTEM INCOME TAXES

Third Quarter of 2020 Compared to Third Quarter of 2019

Income Tax Expense decreased $42 million primarily due to the recognition of a $52 million discrete tax adjustment in 2020, which was attributable to the 5-year net operating loss carryback provision of the CARES Act.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Income Tax Expense increased $27 million primarily due to a decrease in amortization of Excess ADIT, partially offset by the recognition of the discrete tax adjustment in 2020, which was attributable to the 5-year net operating loss carryback provision of the CARES Act.

40

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

 	September 30, 2020		December 31, 2019	
 	(dollars in millions)	
Long-term Debt, including amounts due within one year	$	30,067.1 			56.6 	%		$	26,725.5 			54.1 	%	
Short-term Debt	2,397.0 			4.5 			2,838.3 			5.7 		
Total Debt	32,464.1 			61.1 			29,563.8 			59.8 		
AEP Common Equity	20,365.9 			38.4 			19,632.2 			39.6 		
Noncontrolling Interests	268.7 			0.5 			281.0 			0.6 		
Total Debt and Equity Capitalization	$	53,098.7 			100.0 	%		$	49,477.0 			100.0 	%	

AEP’s ratio of debt-to-total capital increased from 59.8% as of December 31, 2019 to 61.1% as of September 30, 2020 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 September 30, 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.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of September 30, 2020, available liquidity was approximately $3.8 billion as illustrated in the table below:

		Amount		Maturity	
Commercial Paper Backup:	(in millions)			
	Revolving Credit Facility	$	4,000.0 			June 2022	
 	364-Day Term Loan	1,000.0 			March 2021	
Cash and Cash Equivalents	409.7 			 	
Total Liquidity Sources	5,409.7 			 	
Less:	AEP Commercial Paper Outstanding	650.0 			 	
 	364-Day Term Loan	1,000.0 			 	
					
Net Available Liquidity	$	3,759.7 			 	

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries.  The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers.  The maximum amount of commercial paper outstanding during the first nine months of 2020 was $3 billion.  The weighted-average interest rate for AEP’s commercial paper during 2020 was 1.56%.
41

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 September 30, 2020 was $197 million with maturities ranging from October 2020 to August 2021.

Securitized Accounts Receivables

AEP’s 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 September 30, 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, receivables would no longer be purchased by the bank conduits and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity.

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements.  Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of September 30, 2020, this contractually-defined percentage was 57.7%. 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.

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

See Note 12 - Financing Activities for additional information.

42

Dividend Policy and Restrictions

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

Credit Ratings

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

CASH FLOW

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

	Nine Months Ended 
September 30,	
 	2020		2019	
 	(in millions)	
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	432.6 			$	444.1 		
Net Cash Flows from Operating Activities	2,922.2 			3,349.9 		
Net Cash Flows Used for Investing Activities	(4,707.3)			(5,357.6)		
Net Cash Flows from Financing Activities	1,816.3 			2,053.4 		
	
Net Increase in Cash, Cash Equivalents and Restricted Cash	31.2 			45.7 		
Cash, Cash Equivalents and Restricted Cash at End of Period	$	463.8 			$	489.8 		

43

Operating Activities

	Nine Months Ended 
September 30,	
	2020		2019	
	(in millions)	
Net Income	$	1,762.0 			$	1,767.1 		
Non-Cash Adjustments to Net Income (a)	2,094.3 			1,838.8 		
Mark-to-Market of Risk Management Contracts	46.4 			(41.6)		
Pension Contributions to Qualified Plan Trust	(110.3)			— 		
Property Taxes	396.9 			341.7 		
Deferred Fuel Over/Under-Recovery, Net	27.4 			93.7 		
Recovery of Ohio Capacity Costs	— 			34.1 		
Refund of Global Settlement	— 			(12.4)		
Change in Other Noncurrent Assets	(219.6)			(9.6)		
Change in Other Noncurrent Liabilities	(25.1)			(16.3)		
Change in Certain Components of Working Capital	(1,049.8)			(645.6)		
Net Cash Flows from Operating Activities	$	2,922.2 			$	3,349.9 		

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

Net Cash Flows from Operating Activities decreased by $428 million primarily due to the following:
•A $404 million decrease in cash from the Change in Certain Components of Working Capital. The decrease is primarily due to timing of accounts receivable, an increase in employee-related payments and a decrease in accrued taxes primarily due to increased property tax payments.
•A $210 million decrease in Changes in Other Noncurrent Assets primarily due to a change in regulatory assets as a result of deferred storm costs related to Hurricane Laura in 2020 and the settlement of deferred restoration costs from the Texas Storm Cost Securitization financing order received in 2019. See Note 4 - Rate Matters for additional information.
•A $110 million decrease in cash due to a discretionary contribution to the qualified pension plan. See Note 7 - Benefit Plans for additional information.
These decreases in cash were partially offset by:
•A $250 million increase in cash from Income from Continuing Operations, after non-cash adjustments. See Results of Operations for further detail.
•An $88 million increase in fair value of risk management contracts due to pricing movement in the commodities markets.

44

Investing Activities

	Nine Months Ended 
September 30,	
 	2020		2019	
 	(in millions)	
Construction Expenditures	$	(4,690.4)			$	(4,336.0)		
Acquisitions of Nuclear Fuel	(68.4)			(91.9)		

Acquisition of Sempra Renewables LLC and Santa Rita East, Net of Cash and Restricted Cash Acquired	— 			(921.3)		
Other	51.5 			(8.4)		
Net Cash Flows Used for Investing Activities	$	(4,707.3)			$	(5,357.6)		

Net Cash Flows Used for Investing Activities decreased by $650 million primarily due to the following:
•A $921 million decrease due to the 2019 acquisition of Sempra Renewables LLC and Santa Rita East. The $921 million represented a cash payment of $939 million, net of cash acquired of $18 million. See Note 6 - Acquisition and Dispositions for additional information.
This decrease in the use of cash was partially offset by:
•A $354 million increase in construction expenditures, primarily due to increases at AEP Transmission Holdco of $189 million, Generation & Marketing of $76 million and Transmission and Distribution Utilities of $55 million.

Financing Activities

	Nine Months Ended 
September 30,	
 	2020		2019	
 	(in millions)	
Issuance of Common Stock	$	136.5 			$	44.7 		
Issuance/Retirement of Debt, Net	2,844.0 			3,063.9 		
	
Dividends Paid on Common Stock	(1,055.7)			(1,002.0)		
Other	(108.5)			(53.2)		
Net Cash Flows from Financing Activities	$	1,816.3 			$	2,053.4 		

Net Cash Flows from Financing Activities decreased by $237 million primarily due to the following:
•A $1 billion decrease in short-term debt primarily due to increased repayments of commercial paper. See Note 12 - Financing Activities for additional information.
This decrease in cash was partially offset by:
•A $493 million increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.
•A $323 million decrease in the retirement of long-term debt. See Note 12 - Financing Activities for additional information.

See “Long-term Debt Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after September 30, 2020 through October 22, 2020, the date that the third quarter 10-Q was issued.

BUDGETED CAPITAL EXPENDITURES

Management currently estimates $5.9 billion of capital expenditures for 2020 and forecasts approximately $34.9 billion of capital expenditures for 2020 to 2024. In the second quarter of 2020, management revised the capital expenditure forecast for 2020 to 2024 to include approximately $2 billion of capital expenditures for North Central Wind Energy Facilities. 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,
45

weather, legal reviews and the ability to access capital.  Management expects to fund these capital expenditures through cash flows from operations and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. For complete information of forecasted capital expenditures, see the “Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2019 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

ACCOUNTING STANDARDS

See Note 2 - New Accounting Standards for information related to accounting standards 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
46

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

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)	
Nine Months Ended September 30, 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	(43.8)			(5.1)			(16.6)			(65.5)		
Fair Value of New Contracts at Inception When Entered During the Period (a)	— 			— 			12.0 			12.0 		
	
Changes in Fair Value Due to Market Fluctuations During the Period (b)	— 			— 			10.7 			10.7 		
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	26.9 			(4.9)			— 			22.0 		
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2020	$	59.0 			$	(113.6)			$	169.5 			114.9 		
Commodity Cash Flow Hedge Contracts			 				(55.6)		
Interest Rate Cash Flow Hedge Contracts			 		 		(4.7)		
	
Collateral Deposits			 		 		8.7 		
	
Total MTM Derivative Contract Net Assets as of September 30, 2020			 		 		$	63.3 		

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

47

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 September 30, 2020, credit exposure net of collateral to sub investment grade counterparties was approximately 7.2%, 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 September 30, 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		$	401.8 			$	— 			$	401.8 			2 			$	194.8 		
Split Rating		0.8 			— 			0.8 			1 			0.8 		
	
No External Ratings:		 		 				 		 	
Internal Investment Grade		128.0 			— 			128.0 			3 			87.1 		
Internal Noninvestment Grade		51.9 			10.5 			41.4 			2 			28.0 		
Total as of September 30, 2020		$	582.5 			$	10.5 			$	572.0 						

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 September 30, 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. The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:

48

VaR Model
Trading Portfolio

Nine Months Ended		Twelve Months Ended	
September 30, 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

Nine Months Ended		Twelve Months Ended	
September 30, 2020		December 31, 2019	
End		High		Average		Low		End		High		Average		Low	
(in millions)		(in millions)	
$	1.0 			$	1.5 			$	0.8 			$	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 nine months ended September 30, 2020 and 2019, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $18 million and $24 million, respectively.
49

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions, except per-share and share amounts)
(Unaudited)

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2020		2019		2020		2019	
REVENUES									
Vertically Integrated Utilities		$	2,400.1 			$	2,598.9 			$	6,655.4 			$	7,087.6 		
Transmission and Distribution Utilities		1,124.1 			1,147.3 			3,208.7 			3,328.7 		
Generation & Marketing		464.8 			501.2 			1,223.4 			1,323.8 		
Other Revenues		77.4 			67.6 			220.4 			205.3 		
TOTAL REVENUES		4,066.4 			4,315.0 			11,307.9 			11,945.4 		
									
EXPENSES		 		 		 		 	
Fuel and Other Consumables Used for Electric Generation		459.3 			631.2 			1,174.9 			1,662.5 		
Purchased Electricity for Resale		741.1 			783.9 			2,141.4 			2,306.4 		
Other Operation		702.9 			708.3 			1,871.0 			1,981.7 		
Maintenance		237.6 			267.7 			730.5 			890.9 		

Depreciation and Amortization		644.6 			645.2 			1,996.3 			1,873.6 		
Taxes Other Than Income Taxes		337.7 			320.5 			976.3 			932.7 		
TOTAL EXPENSES		3,123.2 			3,356.8 			8,890.4 			9,647.8 		
									
OPERATING INCOME		943.2 			958.2 			2,417.5 			2,297.6 		
									
Other Income (Expense):		 		 		 		 	

Other Income		5.5 			3.2 			15.4 			18.4 		
Allowance for Equity Funds Used During Construction		45.2 			43.0 			111.7 			122.3 		
Non-Service Cost Components of Net Periodic Benefit Cost		29.7 			30.0 			89.2 			90.0 		
	
Interest Expense		(291.3)			(275.1)			(877.4)			(781.6)		
									
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS		732.3 			759.3 			1,756.4 			1,746.7 		
									
Income Tax Expense (Benefit)		(1.2)			40.6 			57.9 			30.7 		
Equity Earnings of Unconsolidated Subsidiaries		14.7 			15.2 			63.5 			51.1 		

	

NET INCOME		748.2 			733.9 			1,762.0 			1,767.1 		
									
Net Income (Loss) Attributable to Noncontrolling Interests		(0.4)			0.4 			(2.6)			(0.5)		
									
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	748.6 			$	733.5 			$	1,764.6 			$	1,767.6 		
									
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING		496,177,968 			493,839,034 			495,479,190 			493,579,430 		

	
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	1.51 			$	1.49 			$	3.56 			$	3.58 		
									
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING		497,458,523 			495,461,509 			496,916,187 			495,105,986 		

	
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	1.50 			$	1.48 			$	3.55 			$	3.57 		

									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
50

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2020		2019		2020		2019	
Net Income		$	748.2 			$	733.9 			$	1,762.0 			$	1,767.1 		
									
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES		 		 		 		 	
Cash Flow Hedges, Net of Tax of $10.5 and $11.8 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $4.7 and $(16.8) for the Nine Months Ended September 30, 2020 and 2019, Respectively		39.3 			44.2 			17.6 			(63.3)		
	
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.5) and $(0.4) for the Three Months Ended September 30, 2020 and 2019, Respectively, and $(1.4) and $(1.1) for the Nine Months Ended September 30, 2020 and 2019, Respectively		(1.8)			(1.4)			(5.3)			(4.2)		
		 		 		 		 	
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		37.5 			42.8 			12.3 			(67.5)		
									
TOTAL COMPREHENSIVE INCOME		785.7 			776.7 			1,774.3 			1,699.6 		
									
Total Other Comprehensive Income (Loss) Attributable To Noncontrolling Interests		(0.4)			0.4 			(2.6)			(0.5)		
									
TOTAL OTHER COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	786.1 			$	776.3 			$	1,776.9 			$	1,700.1 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
51

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

	AEP Common Shareholders					
	Common Stock						Accumulated
Other
Comprehensive
Income (Loss)					
	Shares		Amount		Paid-in
Capital		Retained
Earnings				Noncontrolling
Interests		Total	
TOTAL EQUITY – DECEMBER 31, 2018	513.5 			$	3,337.4 			$	6,486.1 			$	9,325.3 			$	(120.4)			$	31.0 			$	19,059.4 		
														
Issuance of Common Stock	0.1 			1.2 			13.3 			 						14.5 		
Common Stock Dividends							(332.5)		(b)			(1.1)			(333.6)		
Other Changes in Equity					(56.6)		(a)					1.0 			(55.6)		

Net Income	 		 		 		572.8 					1.3 			574.1 		
Other Comprehensive Loss	 		 		 		 		(30.3)					(30.3)		
TOTAL EQUITY – MARCH 31, 2019	513.6 			3,338.6 			6,442.8 			9,565.6 			(150.7)			32.2 			19,228.5 		
														
Issuance of Common Stock	0.4 			2.2 			15.6 			 		 		 		17.8 		
Common Stock Dividends	 		 		 		(332.7)		(b)	 		(1.8)			(334.5)		
Other Changes in Equity	 		 		(3.1)					 		0.6 			(2.5)		
Acquisition of Sempra Renewables LLC											134.8 			134.8 		
Net Income (Loss)	 		 		 		461.3 			 		(2.2)			459.1 		
Other Comprehensive Loss	 		 		 		 		(80.0)			 		(80.0)		
TOTAL EQUITY – JUNE 30, 2019	514.0 			3,340.8 			6,455.3 			9,694.2 			(230.7)			163.6 			19,423.2 		
														
Issuance of Common Stock	0.1 			1.1 			11.3 									12.4 		
Common Stock Dividends							(332.4)		(b)			(1.5)			(333.9)		
Other Changes in Equity					0.5 									0.5 		
Acquisition of Santa Rita East											118.8 			118.8 		
Net Income							733.5 					0.4 			733.9 		
Other Comprehensive Income									42.8 					42.8 		
TOTAL EQUITY – SEPTEMBER 30, 2019	514.1 			$	3,341.9 			$	6,467.1 			$	10,095.3 			$	(187.9)			$	281.3 			$	19,997.7 		
														
TOTAL EQUITY – DECEMBER 31, 2019	514.4 			$	3,343.4 			$	6,535.6 			$	9,900.9 			$	(147.7)			$	281.0 			$	19,913.2 		
														
Issuance of Common Stock	1.0 			6.8 			49.3 									56.1 		
Common Stock Dividends							(359.1)		(c)			(4.6)			(363.7)		
Other Changes in Equity					(29.0)							(1.2)			(30.2)		
ASU 2016-13 Adoption							1.8 							1.8 		
Net Income							495.2 					4.1 			499.3 		
Other Comprehensive Loss									(68.8)					(68.8)		
TOTAL EQUITY – MARCH 31, 2020	515.4 			3,350.2 			6,555.9 			10,038.8 			(216.5)			279.3 			20,007.7 		
														
Issuance of Common Stock	0.8 			5.2 			49.7 									54.9 		
Common Stock Dividends							(337.7)		(c)			(3.2)			(340.9)		
Other Changes in Equity					(2.6)							1.0 			(1.6)		
	
Net Income (Loss)							520.8 					(6.3)			514.5 		
Other Comprehensive Income									43.6 					43.6 		
TOTAL EQUITY – JUNE 30, 2020	516.2 			3,355.4 			6,603.0 			10,221.9 			(172.9)			270.8 			20,278.2 		
														
Issuance of Common Stock	0.4 			2.2 			23.3 			 		 		 		25.5 		
Common Stock Dividends	 				 		(349.1)		(c)	 		(2.0)			(351.1)		
Other Changes in Equity	 		 		(104.0)		(d)			 		0.3 			(103.7)		
	
Net Income (Loss)	 		 		 		748.6 			 		(0.4)			748.2 		
Other Comprehensive Income	 		 		 		 		37.5 			 		37.5 		
TOTAL EQUITY – SEPTEMBER 30, 2020	516.6 			$	3,357.6 			$	6,522.3 			$	10,621.4 			$	(135.4)			$	268.7 			$	20,634.6 		

(a)Includes $(62) million related to a forward equity purchase contract associated with the issuance of Equity Units.
(b)Cash dividends declared per AEP common share were $0.67.
(c)Cash dividends declared per AEP common share were $0.70.
(d)Includes $(121) million related to a forward equity purchase contract associated with the issuance of Equity Units.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
52

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)

 		September 30,		December 31,	
 		2020		2019	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	409.7 			$	246.8 		
Restricted Cash
(September 30, 2020 and December 31, 2019 Amounts Include $54.1 and $185.8, Respectively, Related to Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Santa Rita East)		54.1 			185.8 		
Other Temporary Investments
(September 30, 2020 and December 31, 2019 Amounts Include $198 and $187.8, Respectively, Related to EIS and Transource Energy)		209.0 			202.7 		
Accounts Receivable:		 		 	
Customers		600.5 			625.3 		
Accrued Unbilled Revenues		212.4 			222.4 		
Pledged Accounts Receivable – AEP Credit		1,055.1 			873.9 		
Miscellaneous		46.1 			27.2 		
Allowance for Uncollectible Accounts		(63.4)			(43.7)		
Total Accounts Receivable		1,850.7 			1,705.1 		
Fuel		586.1 			528.5 		
Materials and Supplies		681.2 			640.7 		
Risk Management Assets		115.2 			172.8 		
	
Regulatory Asset for Under-Recovered Fuel Costs		61.4 			92.9 		
Margin Deposits		54.1 			60.4 		
	
Prepayments and Other Current Assets		316.7 			242.1 		
TOTAL CURRENT ASSETS		4,338.2 			4,077.8 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Generation		23,036.9 			22,762.4 		
Transmission		26,539.1 			24,808.6 		
Distribution		23,459.8 			22,443.4 		
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)		5,204.7 			4,811.5 		
Construction Work in Progress		4,662.5 			4,319.8 		
Total Property, Plant and Equipment		82,903.0 			79,145.7 		
Accumulated Depreciation and Amortization		20,116.6 			19,007.6 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		62,786.4 			60,138.1 		
					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		3,518.8 			3,158.8 		
Securitized Assets		684.0 			858.1 		
Spent Nuclear Fuel and Decommissioning Trusts		3,075.9 			2,975.7 		
Goodwill		52.5 			52.5 		
Long-term Risk Management Assets		242.9 			266.6 		
Operating Lease Assets		881.0 			957.4 		
Deferred Charges and Other Noncurrent Assets		3,109.6 			3,407.3 		
TOTAL OTHER NONCURRENT ASSETS		11,564.7 			11,676.4 		
					
TOTAL ASSETS		$	78,689.3 			$	75,892.3 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
53

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2020 and December 31, 2019
(in millions, except per-share and share amounts)
(Unaudited)

 		 		 			September 30,		December 31,	
 							2020		2019	
CURRENT LIABILITIES		 		 	
Accounts Payable							$	1,659.6 			$	2,085.8 		
Short-term Debt:							 		 	
Securitized Debt for Receivables – AEP Credit							703.0 			710.0 		
Other Short-term Debt							1,694.0 			2,128.3 		
Total Short-term Debt							2,397.0 			2,838.3 		
Long-term Debt Due Within One Year
(September 30, 2020 and December 31, 2019 Amounts Include $176.6 and $565.1, Respectively, Related to Transition Funding, DCC Fuel, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding)			1,911.6 			1,598.7 		
Risk Management Liabilities							62.4 			114.3 		
Customer Deposits							339.7 			366.1 		
Accrued Taxes							942.7 			1,357.8 		
Accrued Interest							331.0 			243.6 		
Obligations Under Operating Leases							236.5 			234.1 		
Regulatory Liability for Over-Recovered Fuel Costs					82.5 			86.6 		
	
Other Current Liabilities							1,084.2 			1,373.8 		
TOTAL CURRENT LIABILITIES							9,047.2 			10,299.1 		
								
NONCURRENT LIABILITIES		 		 	
Long-term Debt
(September 30, 2020 and December 31, 2019 Amounts Include $958.7 and $907, Respectively, Related to Transition Funding, DCC Fuel, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding)			28,155.5 			25,126.8 		
Long-term Risk Management Liabilities							232.4 			261.8 		
Deferred Income Taxes							8,011.4 			7,588.2 		
Regulatory Liabilities and Deferred Investment Tax Credits			8,249.2 			8,457.6 		
Asset Retirement Obligations							2,448.3 			2,216.6 		
Employee Benefits and Pension Obligations							353.1 			466.0 		
Obligations Under Operating Leases							690.5 			734.6 		
Deferred Credits and Other Noncurrent Liabilities			794.6 			719.8 		
TOTAL NONCURRENT LIABILITIES							48,935.0 			45,571.4 		
										
TOTAL LIABILITIES							57,982.2 			55,870.5 		
										
Rate Matters (Note 4)										
Commitments and Contingencies (Note 5)										
										
MEZZANINE EQUITY					
Redeemable Noncontrolling Interest							— 			65.7 		
Contingently Redeemable Performance Share Awards							72.5 			42.9 		
TOTAL MEZZANINE EQUITY							72.5 			108.6 		
										
EQUITY		 		 	
Common Stock – Par Value – $6.50 Per Share:							 		 	
		2020		2019			 		 	
Shares Authorized		600,000,000		600,000,000			 		 	
Shares Issued		516,551,408		514,373,631			 		 	
(20,204,160 Shares were Held in Treasury as of September 30, 2020 and December 31, 2019, Respectively)			3,357.6 			3,343.4 		
Paid-in Capital							6,522.3 			6,535.6 		
Retained Earnings							10,621.4 			9,900.9 		
Accumulated Other Comprehensive Income (Loss)			(135.4)			(147.7)		
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			20,365.9 			19,632.2 		
										
Noncontrolling Interests							268.7 			281.0 		
										
TOTAL EQUITY							20,634.6 			19,913.2 		
										
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY		$	78,689.3 			$	75,892.3 		
										
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
54

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Nine Months Ended September 30,	
 		2020		2019	
OPERATING ACTIVITIES		 		 	
Net Income		$	1,762.0 			$	1,767.1 		

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:		 		 	
Depreciation and Amortization		1,996.3 			1,873.6 		
	
Deferred Income Taxes		142.5 			15.9 		

Allowance for Equity Funds Used During Construction		(111.7)			(122.3)		
Mark-to-Market of Risk Management Contracts		46.4 			(41.6)		
Amortization of Nuclear Fuel		67.2 			71.6 		
Pension Contributions to Qualified Plan Trust		(110.3)			— 		
Property Taxes		396.9 			341.7 		
Deferred Fuel Over/Under-Recovery, Net		27.4 			93.7 		

Recovery of Ohio Capacity Costs		— 			34.1 		
Refund of Global Settlement		— 			(12.4)		
Change in Other Noncurrent Assets		(219.6)			(9.6)		
Change in Other Noncurrent Liabilities		(25.1)			(16.3)		
Changes in Certain Components of Working Capital:		 		 	
Accounts Receivable, Net		(138.9)			125.0 		
Fuel, Materials and Supplies		(97.4)			(116.6)		
Accounts Payable		21.9 			(32.4)		
Accrued Taxes, Net		(502.9)			(359.9)		
Other Current Assets		26.0 			60.2 		
Other Current Liabilities		(358.5)			(321.9)		
Net Cash Flows from Operating Activities		2,922.2 			3,349.9 		
					
INVESTING ACTIVITIES		 		 	
Construction Expenditures		(4,690.4)			(4,336.0)		
	
Purchases of Investment Securities		(1,329.5)			(951.5)		
Sales of Investment Securities		1,293.0 			874.2 		
Acquisitions of Nuclear Fuel		(68.4)			(91.9)		
Acquisition of Sempra Renewables LLC and Santa Rita East, Net of Cash and Restricted Cash Acquired		— 			(921.3)		

	
Other Investing Activities		88.0 			68.9 		
Net Cash Flows Used for Investing Activities		(4,707.3)			(5,357.6)		
					
FINANCING ACTIVITIES		 		 	
Issuance of Common Stock		136.5 			44.7 		
Issuance of Long-term Debt		3,985.8 			3,492.4 		
Issuance of Short-term Debt with Original Maturities greater than 90 Days		1,304.5 			— 		
Change in Short-term Debt with Original Maturities less than 90 Days, Net		(1,445.8)			600.0 		
Retirement of Long-term Debt		(700.5)			(1,023.5)		
Make Whole Premium on Extinguishment of Long-term Debt		— 			(5.0)		
Redemption of Short-term Debt with Original Maturities Greater than 90 Days		(300.0)			— 		
Principal Payments for Finance Lease Obligations		(46.3)			(44.5)		
Dividends Paid on Common Stock		(1,055.7)			(1,002.0)		
Redemption of Noncontrolling Interest in Trent and Desert Sky Windfarms		(56.5)			— 		
Other Financing Activities		(5.7)			(8.7)		
Net Cash Flows from Financing Activities		1,816.3 			2,053.4 		

	

Net Increase in Cash, Cash Equivalents and Restricted Cash		31.2 			45.7 		
Cash, Cash Equivalents and Restricted Cash at Beginning of Period		432.6 			444.1 		
Cash, Cash Equivalents and Restricted Cash at End of Period		$	463.8 			$	489.8 		
					
SUPPLEMENTARY INFORMATION					
Cash Paid for Interest, Net of Capitalized Amounts		$	690.5 			$	689.7 		
Net Cash Paid (Received) for Income Taxes		(23.9)			22.8 		
Noncash Acquisitions Under Finance Leases		33.0 			66.7 		
Construction Expenditures Included in Current Liabilities as of September 30,		830.1 			1,018.9 		
Construction Expenditures Included in Noncurrent Liabilities as of September 30,		8.3 			— 		
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,		1.0 			— 		
	
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage		2.4 			— 		
Noncontrolling Interest assumed with Sempra Renewable LLC and Santa Rita East Acquisition		— 			253.4 		
Liabilities assumed with Sempra Renewable LLC and Santa Rita East Acquisition		— 			32.4 		
Forward Equity Purchase Contract Included in Current and Noncurrent Liabilities as of September 30,		120.6 			52.4 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
55

AEP TEXAS INC.
AND SUBSIDIARIES

56

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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

 	Three Months Ended		Nine Months Ended	
	September 30,		September 30,	
 	2020		2019		2020		2019	
 	(in millions of KWhs)	
Retail:	 		 					
Residential	4,112 			4,148 			9,736 			9,580 		
Commercial	2,941 			3,152 			7,700 			7,997 		
Industrial	2,037 			2,168 			6,618 			6,556 		
Miscellaneous	184 			197 			486 			512 		
Total Retail	9,274 			9,665 			24,540 			24,645 		

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

Summary of Heating and Cooling Degree Days

 	Three Months Ended		Nine Months Ended	
	September 30,		September 30,	
 	2020		2019		2020		2019	
 	(in degree days)	
Actual – Heating (a)	1 			— 			98 			180 		
Normal – Heating (b)	— 			— 			188 			190 		
								
Actual – Cooling (c)	1,357 			1,587 			2,524 			2,679 		
Normal – Cooling (b)	1,378 			1,368 			2,436 			2,425 		

(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.

57

Third Quarter of 2020 Compared to Third Quarter of 2019

Reconciliation of Third Quarter of 2019 to Third Quarter of 2020	
Net Income	
(in millions)	
	
Third Quarter of 2019		$	77.0 		
 		 	
Changes in Gross Margin:			
Retail Margins		(1.4)		
Margins from Off-system Sales		(0.4)		
Transmission Revenues		4.3 		
Other Revenues		(59.0)		
Total Change in Gross Margin		(56.5)		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(4.8)		
Depreciation and Amortization		62.5 		
Taxes Other Than Income Taxes		1.1 		
	
Interest Income		0.1 		
	
Allowance for Equity Funds Used During Construction		(0.7)		
	
Interest Expense		(8.7)		
Total Change in Expenses and Other		49.5 		
 		 	
Income Tax Expense		12.6 		
 		 	
Third Quarter of 2020		$	82.6 		

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 decreased $1 million primarily due to the following:
•A $19 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.
•An $11 million decrease in weather-related usage primarily due to a 14% decrease in cooling degree days.
•A $3 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
These decreases were partially offset by:
•A $19 million increase in weather-normalized margins primarily in the residential class.
•A $6 million increase from interim rate increases driven by increased distribution investment.
•A $5 million increase due to new base rates implemented in June 2020.
•Transmission Revenues increased $4 million primarily due to:
•An $11 million increase from interim rate increases driven by increased transmission investment.
This increase was partially offset by:
•A $7 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 $59 million primarily due to the following:
•A $68 million decrease in securitization revenues primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.
This decrease was partially offset by:
•An $8 million increase in revenues due to the amortization of a provision for refund recorded in December 2019 as part of the most recent base rate case. This increase was partially offset in Retail Margins and Transmission Revenues above.
58

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

•Other Operation and Maintenance expenses increased $5 million primarily due to the following:
•A $5 million increase due to the write-off of land associated with the Oklaunion Power Station.
•A $4 million increase in transmission expenses. This increase was partially offset in Gross Margin above.
These increases were partially offset by:
•A $3 million decrease in distribution expenses.
•Depreciation and Amortization expenses decreased $63 million primarily due to a 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 in Interest Expense below.
•Interest Expense increased $9 million primarily due to the following:
•A $5 million increase due to higher long-term debt balances.
•A $3 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.
•Income Tax Expense decreased $13 million primarily due to an increase in amortization of Excess ADIT and the recognition of a discrete tax adjustment in 2020 which was primarily attributable to the 5-year net operating loss carryback provision of the CARES Act. This decrease was partially offset above in Gross Margins and in Other Operation and Maintenance expenses.
59

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020	
Net Income	
(in millions)	
	
Nine Months Ended September 30, 2019		$	192.0 		
 		 	
Changes in Gross Margin:			
Retail Margins		2.7 		
Margins from Off-system Sales		(20.2)		
Transmission Revenues		8.9 		
Other Revenues		(36.8)		
Total Change in Gross Margin		(45.4)		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		77.3 		
Depreciation and Amortization		29.0 		
Taxes Other Than Income Taxes		3.6 		
	
Interest Income		(0.3)		
	
Allowance for Equity Funds Used During Construction		6.1 		
	
Interest Expense		(36.5)		
Total Change in Expenses and Other		79.2 		
 		 	
Income Tax Expense		(28.7)		
 		 	
Nine Months Ended September 30, 2020		$	197.1 		

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 $3 million primarily due to the following:
•A $21 million increase in weather-normalized margins primarily driven by the residential class and partially offset by a decrease in the industrial class.
•A $7 million increase from interim rate increases driven by increased transmission investment.
•A $7 million increase from interim rate increases driven by increased distribution investment.
•A $7 million increase due to new base rates implemented in June 2020.
•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 $25 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 $15 million decrease in weather-related usage primarily due to a 6% decrease in cooling degree days and a 46% decrease in heating degree days.
•A $4 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
•Margins from Off-system Sales decreased $20 million primarily due to lower Oklaunion Power Station PPA revenues. This decrease was partially offset in Other Operation and Maintenance expenses below.
•Transmission Revenues increased $9 million primarily due to the following:
•A $30 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.
•A $7 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
60

•Other Revenues decreased $37 million primarily due to the following:
•A $49 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 $11 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 $77 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.
These decreases were partially offset by:
•A $9 million increase in transmission expenses. This increase was partially offset in Gross Margin above.
•A $5 million increase due to the write-off of land associated with the Oklaunion Power Station.
•Depreciation and Amortization expenses decreased $29 million primarily due to the following:
•A $43 million decrease in securitization amortizations due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This increase was offset in Other Revenues above and in Interest Expense below.
This decrease was partially offset by:
•A $14 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 $6 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 $37 million primarily due to:
•A $24 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 $9 million increase due to higher long-term debt balances.
•A $6 million increase due to due to a decrease in the debt component of AFUDC.
These increases were partially offset by:
•A $5 million decrease due to lower short-term debt balances.
•Income Tax Expense increased $29 million primarily due to 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 partially offset by current year amortization of Excess ADIT and an increase in favorable AFUDC Equity tax benefit. This increase was partially offset in Gross Margins and Other Operation and Maintenance Expenses above.
61

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 	 	Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
 	 	2020	 	2019		2020		2019	
REVENUES	 	 	 	 					
Electric Transmission and Distribution	 	$	390.1 			$	445.4 			$	1,165.2 			$	1,190.3 		
Sales to AEP Affiliates	 	41.4 			42.7 			89.4 			125.1 		
Other Revenues	 	0.5 			1.2 			2.5 			2.6 		
TOTAL REVENUES	 	432.0 			489.3 			1,257.1 			1,318.0 		
	 								
EXPENSES	 	 		 		 		 	
Fuel and Other Consumables Used for Electric Generation		10.4 			11.2 			13.6 			29.1 		
Other Operation	 	134.3 			128.2 			344.7 			349.2 		
Maintenance	 	20.4 			21.7 			64.1 			136.9 		
Depreciation and Amortization	 	107.7 			170.2 			435.8 			464.8 		
Taxes Other Than Income Taxes	 	38.7 			39.8 			106.7 			110.3 		
TOTAL EXPENSES	 	311.5 			371.1 			964.9 			1,090.3 		
	 								
OPERATING INCOME	 	120.5 			118.2 			292.2 			227.7 		
	 								
Other Income (Expense):	 	 		 		 		 	
Interest Income	 	0.5 			0.4 			1.2 			1.5 		
	
Allowance for Equity Funds Used During Construction		4.4 			5.1 			14.4 			8.3 		
	
Non-Service Cost Components of Net Periodic Benefit Cost		2.8 			2.8 			8.4 			8.4 		
Interest Expense	 	(44.5)			(35.8)			(129.2)			(92.7)		
	 								
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	 	83.7 			90.7 			187.0 			153.2 		
	 								
Income Tax Expense (Benefit)	 	1.1 			13.7 			(10.1)			(38.8)		
									
NET INCOME	 	$	82.6 			$	77.0 			$	197.1 			$	192.0 		
									
The common stock of AEP Texas is wholly-owned by Parent.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
62

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2020		2019		2020		2019	
Net Income		$	82.6 			$	77.0 			$	197.1 			$	192.0 		
 									
OTHER COMPREHENSIVE INCOME, NET OF TAXES		 						 	
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0.2 and $0.2 for the Nine Months Ended September 30, 2020 and 2019, Respectively		0.3 			0.3 			0.8 			0.8 		
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2020 and 2019, Respectively		— 			— 			0.1 			0.1 		
									
TOTAL OTHER COMPREHENSIVE INCOME		0.3 			0.3 			0.9 			0.9 		
									
TOTAL COMPREHENSIVE INCOME		$	82.9 			$	77.3 			$	198.0 			$	192.9 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	

63

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018		$	1,257.9 			$	1,337.7 			$	(15.1)			$	2,580.5 		
									
Capital Contribution from Parent		200.0 							200.0 		
	
Net Income				34.4 					34.4 		
Other Comprehensive Income						0.3 			0.3 		
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019		1,457.9 			1,372.1 			(14.8)			2,815.2 		

Net Income		 		80.6 			 		80.6 		
Other Comprehensive Income		 		 		0.3 			0.3 		
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019		1,457.9 			1,452.7 			(14.5)			2,896.1 		

Net Income				77.0 					77.0 		
Other Comprehensive Income						0.3 			0.3 		
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019		$	1,457.9 			$	1,529.7 			$	(14.2)			$	2,973.4 		
									
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019		$	1,457.9 			$	1,516.0 			$	(12.8)			$	2,961.1 		

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

Net Income		 		66.9 					66.9 		
Other Comprehensive Income		 				0.3 			0.3 		
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2020		1,457.9 			1,630.5 			(12.2)			3,076.2 		

Net Income				82.6 					82.6 		
Other Comprehensive Income						0.3 			0.3 		
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2020		$	1,457.9 			$	1,713.1 			$	(11.9)			$	3,159.1 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	

64

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)

 	 	September 30,		December 31,	
 	 	2020	 	2019	
CURRENT ASSETS	 	 	 	 	
Cash and Cash Equivalents		$	0.1 			$	3.1 		
Restricted Cash
(September 30, 2020 and December 31, 2019 Amounts Include $44.8 and $154.7, Respectively, Related to Transition Funding and Restoration Funding)		44.8 			154.7 		
Advances to Affiliates		148.4 			207.2 		
Accounts Receivable:	 	 		 	
Customers	 	136.8 			116.0 		
Affiliated Companies	 	22.0 			10.1 		
Accrued Unbilled Revenues		74.8 			68.8 		
Miscellaneous	 	— 			0.3 		
Allowance for Uncollectible Accounts		— 			(1.8)		
Total Accounts Receivable	 	233.6 			193.4 		
Fuel	 	— 			5.9 		
Materials and Supplies	 	72.0 			56.7 		
	
Accrued Tax Benefits		9.6 			66.1 		
Prepayments and Other Current Assets	 	5.6 			5.8 		
TOTAL CURRENT ASSETS	 	514.1 			692.9 		
	 				
PROPERTY, PLANT AND EQUIPMENT	 	 		 	
Electric:	 	 		 	
Generation		— 			351.7 		
Transmission	 	4,943.8 			4,466.5 		
Distribution	 	4,486.6 			4,215.2 		
Other Property, Plant and Equipment	 	868.2 			805.9 		
Construction Work in Progress	 	787.9 			763.9 		
Total Property, Plant and Equipment	 	11,086.5 			10,603.2 		
Accumulated Depreciation and Amortization	 	1,541.5 			1,758.1 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	 	9,545.0 			8,845.1 		
	 				
OTHER NONCURRENT ASSETS	 	 		 	
Regulatory Assets	 	275.4 			280.6 		
Securitized Assets
(September 30, 2020 and December 31, 2019 Amounts Include $467.8 and $621.2, Respectively, Related to Transition Funding and Restoration Funding)		467.8 			623.4 		
	
Deferred Charges and Other Noncurrent Assets	 	182.7 			147.1 		
TOTAL OTHER NONCURRENT ASSETS	 	925.9 			1,051.1 		
	 				
TOTAL ASSETS	 	$	10,985.0 			$	10,589.1 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
65

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)

 	 	September 30,		December 31,	
 	 	2020	 	2019	
CURRENT LIABILITIES	 				
	
Accounts Payable:	 				
General	 	$	235.3 			$	256.8 		
Affiliated Companies	 	27.2 			35.6 		
Short-term Debt – Nonaffiliated		2.0 			— 		
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2020 and December 31, 2019 Amounts Include $87.7 and $281.4, Respectively, Related to Transition Funding and Restoration Funding)		87.8 			392.1 		
Risk Management Liabilities		0.1 			— 		
	
Accrued Taxes	 	101.8 			84.9 		
Accrued Interest
(September 30, 2020 and December 31, 2019 Amounts Include $3.5 and $7.5, Respectively, Related to Transition Funding and Restoration Funding)		54.7 			35.7 		
Oklaunion Purchase Power Agreement		— 			22.1 		
Obligations Under Operating Leases		13.7 			12.0 		
Provision for Refund		31.6 			64.7 		
Other Current Liabilities	 	92.2 			123.3 		
TOTAL CURRENT LIABILITIES	 	646.4 			1,027.2 		
	 				
NONCURRENT LIABILITIES	 	 		 	
Long-term Debt – Nonaffiliated
(September 30, 2020 and December 31, 2019 Amounts Include $440.2 and $495.4, Respectively, Related to Transition Funding and Restoration Funding)		4,766.9 			4,166.3 		
	
Deferred Income Taxes	 	1,004.4 			965.4 		
Regulatory Liabilities and Deferred Investment Tax Credits	 	1,282.6 			1,316.9 		
	
Obligations Under Operating Leases		71.0 			71.1 		
Deferred Credits and Other Noncurrent Liabilities	 	54.6 			81.1 		
TOTAL NONCURRENT LIABILITIES	 	7,179.5 			6,600.8 		
	 				
TOTAL LIABILITIES	 	7,825.9 			7,628.0 		
	 				
Rate Matters (Note 4)					
Commitments and Contingencies (Note 5)	 				
	 				
COMMON SHAREHOLDER’S EQUITY	 	 		 	
Paid-in Capital	 	1,457.9 			1,457.9 		
Retained Earnings	 	1,713.1 			1,516.0 		
Accumulated Other Comprehensive Income (Loss)		(11.9)			(12.8)		
TOTAL COMMON SHAREHOLDER’S EQUITY	 	3,159.1 			2,961.1 		
	 				
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	 	$	10,985.0 			$	10,589.1 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
66

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 	 	Nine Months Ended September 30,	
 	 	2020	 	2019	
OPERATING ACTIVITIES	 	 	 	 	
Net Income	 	$	197.1 			$	192.0 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:	 	 		 	
Depreciation and Amortization	 	435.8 			464.8 		
Deferred Income Taxes	 	(11.5)			(0.6)		
Allowance for Equity Funds Used During Construction		(14.4)			(8.3)		
Mark-to-Market of Risk Management Contracts	 	0.1 			0.2 		
Pension Contributions to Qualified Plan Trust		(11.3)			— 		

Change in Other Noncurrent Assets	 	(77.3)			0.5 		
Change in Other Noncurrent Liabilities	 	(30.0)			6.5 		
Changes in Certain Components of Working Capital:	 	 			
Accounts Receivable, Net	 	(40.2)			(50.0)		
Fuel, Materials and Supplies	 	(9.4)			(0.1)		
Accounts Payable	 	24.2 			17.8 		
	
Accrued Taxes, Net		73.4 			(33.4)		
	
Other Current Assets	 	(0.8)			(0.7)		
Other Current Liabilities	 	(49.8)			(12.9)		
Net Cash Flows from Operating Activities	 	485.9 			575.8 		
	 				
INVESTING ACTIVITIES	 	 		 	
Construction Expenditures	 	(976.1)			(954.5)		
Change in Advances to Affiliates, Net		58.8 			0.3 		
	
Other Investing Activities		24.1 			18.4 		
Net Cash Flows Used for Investing Activities	 	(893.2)			(935.8)		
	 				
FINANCING ACTIVITIES	 	 		 	
Capital Contribution from Parent		— 			200.0 		
Issuance of Long-term Debt – Nonaffiliated		652.8 			627.5 		
Change in Short-term Debt, Net – Nonaffiliated		2.0 			— 		
Change in Advances from Affiliates, Net	 	— 			(141.2)		
Retirement of Long-term Debt – Nonaffiliated	 	(356.5)			(366.8)		
Principal Payments for Finance Lease Obligations	 	(4.7)			(3.8)		
	
Other Financing Activities		0.8 			(1.1)		
Net Cash Flows from Financing Activities	 	294.4 			314.6 		
					
Net Decrease in Cash, Cash Equivalents and Restricted Cash	 	(112.9)			(45.4)		
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	 	157.8 			159.8 		
Cash, Cash Equivalents and Restricted Cash at End of Period	 	$	44.9 			$	114.4 		
	 				
SUPPLEMENTARY INFORMATION	 	 		 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	102.0 			$	95.1 		
Net Cash Paid (Received) for Income Taxes	 	(55.6)			28.7 		
Noncash Acquisitions Under Finance Leases	 	5.1 			6.9 		
Construction Expenditures Included in Current Liabilities as of September 30,	 	167.6 			183.6 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
67

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
68

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

RESULTS OF OPERATIONS

Summary of Investment in Transmission Assets for AEPTCo

		As of September 30,	
		2020		2019	
		(in millions)	
Plant In Service		$	9,240.4 			$	7,409.0 		
Construction Work in Progress		1,680.9 			1,858.4 		
Accumulated Depreciation and Amortization		531.8 			368.8 		
Total Transmission Property, Net		$	10,389.5 			$	8,898.6 		

Third Quarter of 2020 Compared to Third Quarter of 2019

Reconciliation of Third Quarter of 2019 to Third Quarter of 2020	
Net Income	
(in millions)	
			
Third Quarter of 2019		$	107.6 		
			
Changes in Transmission Revenues:			
Transmission Revenues		44.4 		
Total Change in Transmission Revenues		44.4 		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		0.4 		
Depreciation and Amortization		(16.2)		
Taxes Other Than Income Taxes		(9.3)		
Interest Income		(0.6)		
Allowance for Equity Funds Used During Construction		(0.8)		
Interest Expense		(6.3)		
Total Change in Expenses and Other		(32.8)		
			
Income Tax Expense		(1.6)		

Third Quarter of 2020		$	117.6 		

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

•Transmission Revenues increased $44 million primarily due to continued investment in transmission assets.

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

•Depreciation and Amortization expenses increased $16 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $9 million primarily due to higher property taxes as a result of increased transmission investment.
•Interest Expense increased $6 million primarily due to higher long-term debt balances.
69

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020	
Net Income	
(in millions)	
	
Nine Months Ended September 30, 2019		$	347.9 		
 		 	
Changes in Transmission Revenues:		 	
Transmission Revenues		67.7 		
Total Change in Transmission Revenues		67.7 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(8.2)		
Depreciation and Amortization		(48.0)		
Taxes Other Than Income Taxes		(26.6)		
Interest Income		0.2 		
Allowance for Equity Funds Used During Construction		(6.2)		
Interest Expense		(25.6)		
Total Change in Expenses and Other		(114.4)		
 		 	
Income Tax Expense		7.9 		
 		 	
Nine Months Ended September 30, 2020		$	309.1 		

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

•Transmission Revenues increased $68 million primarily due to the following:
•A $147 million increase due to continued investment in transmission assets.
This increase was partially offset by:
•A $62 million decrease as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant subsidiaries.
•A $17 million decrease as a result of the non-affiliated annual transmission formula rate true-up.

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

•Other Operation and Maintenance expenses increased $8 million primarily due to the following:
•A $5 million increase in rent expense.
•A $3 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $48 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $27 million primarily due to higher property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During Construction decreased $6 million primarily due to the following:
•A $12 million decrease driven by the favorable impact of a FERC settlement agreement recorded in 2019.
•An $8 million decrease due to lower CWIP.
These decreases were partially offset by:
•A $13 million increase driven by FERC audit findings recorded in 2019.
•Interest Expense increased $26 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $8 million primarily due to lower pretax book income, partially offset by the recognition of a discrete tax adjustment in 2019.

70

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2020	 	2019	 	2020	 	2019	
REVENUES									
Transmission Revenues		$	62.9 			$	54.0 			$	184.6 			$	162.1 		
Sales to AEP Affiliates		241.2 			205.7 			652.6 			608.0 		
Other Revenues		— 			— 			0.6 			— 		
TOTAL REVENUES		304.1 			259.7 			837.8 			770.1 		
									
EXPENSES		 		 		 		 	
Other Operation		25.3 			26.0 			72.0 			61.7 		
Maintenance		3.5 			3.2 			6.8 			8.9 		
Depreciation and Amortization		61.5 			45.3 			176.4 			128.4 		
Taxes Other Than Income Taxes		52.2 			42.9 			152.8 			126.2 		
TOTAL EXPENSES		142.5 			117.4 			408.0 			325.2 		
									
OPERATING INCOME		161.6 			142.3 			429.8 			444.9 		
									
Other Income (Expense):		 		 		 		 	
Interest Income - Affiliated		0.2 			0.8 			2.3 			2.1 		
Allowance for Equity Funds Used During Construction		20.2 			21.0 			54.9 			61.1 		
	
Interest Expense		(32.7)			(26.4)			(95.1)			(69.5)		
									
INCOME BEFORE INCOME TAX EXPENSE		149.3 			137.7 			391.9 			438.6 		
									
Income Tax Expense		31.7 			30.1 			82.8 			90.7 		
									
NET INCOME		$	117.6 			$	107.6 			$	309.1 			$	347.9 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
71

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

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

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

Net Income				136.0 			136.0 		
TOTAL MEMBER'S EQUITY – JUNE 30, 2019		2,480.6 			1,329.5 			3,810.1 		

Net Income	 			107.6 			107.6 		
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2019	 	$	2,480.6 			$	1,437.1 			$	3,917.7 		
 	 						
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2019	 	$	2,480.6 			$	1,528.9 			$	4,009.5 		
							
Capital Contribution from Member		185.0 					185.0 		
Net Income				117.8 			117.8 		
TOTAL MEMBER'S EQUITY – MARCH 31, 2020		2,665.6 			1,646.7 			4,312.3 		

Dividends Paid to AEP Transmission Holdco				(5.0)			(5.0)		
Net Income				73.7 			73.7 		
TOTAL MEMBER'S EQUITY – JUNE 30, 2020		2,665.6 			1,715.4 			4,381.0 		

Net Income	 	 		117.6 			117.6 		
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2020	 	$	2,665.6 			$	1,833.0 			$	4,498.6 		
							
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
72

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)

 	 	September 30,	 	December 31,	
 	 	2020	 	2019	
CURRENT ASSETS	 	 	 	 	
Advances to Affiliates	 	$	106.7 			$	85.4 		
Accounts Receivable:	 				
Customers	 	34.1 			19.0 		
Affiliated Companies	 	81.1 			66.1 		
	
Total Accounts Receivable	 	115.2 			85.1 		
Materials and Supplies	 	13.6 			13.8 		
	
Prepayments and Other Current Assets	 	5.3 			13.1 		
TOTAL CURRENT ASSETS	 	240.8 			197.4 		
	 				
TRANSMISSION PROPERTY	 	 		 	
Transmission Property	 	8,947.4 			8,137.9 		
Other Property, Plant and Equipment	 	293.0 			269.6 		
Construction Work in Progress	 	1,680.9 			1,485.7 		
Total Transmission Property	 	10,921.3 			9,893.2 		
Accumulated Depreciation and Amortization	 	531.8 			402.3 		
TOTAL TRANSMISSION PROPERTY – NET	 	10,389.5 			9,490.9 		
	 				
OTHER NONCURRENT ASSETS	 	 		 	
	
Regulatory Assets	 	6.8 			4.2 		
Deferred Property Taxes	 	57.2 			193.5 		
Deferred Charges and Other Noncurrent Assets	 	4.4 			4.8 		
TOTAL OTHER NONCURRENT ASSETS	 	68.4 			202.5 		
	 				
TOTAL ASSETS	 	$	10,698.7 			$	9,890.8 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
73

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)

 	 	September 30,	 	December 31,	
 	 	2020	 	2019	
CURRENT LIABILITIES	 	 	 	 	
Advances from Affiliates	 	$	86.8 			$	137.0 		
Accounts Payable:	 			 	
General	 	337.7 			493.4 		
Affiliated Companies	 	62.4 			71.2 		
	
Accrued Taxes	 	216.6 			355.6 		
Accrued Interest	 	48.2 			19.2 		
Obligations Under Operating Leases		2.3 			2.1 		
Other Current Liabilities	 	9.1 			14.6 		
TOTAL CURRENT LIABILITIES	 	763.1 			1,093.1 		
	 				
NONCURRENT LIABILITIES	 	 		 	
Long-term Debt – Nonaffiliated	 	3,947.9 			3,427.3 		
Deferred Income Taxes	 	892.6 			817.8 		
Regulatory Liabilities	 	575.2 			540.9 		
Obligations Under Operating Leases		1.4 			1.9 		
Deferred Credits and Other Noncurrent Liabilities	 	19.9 			0.3 		
TOTAL NONCURRENT LIABILITIES	 	5,437.0 			4,788.2 		
	 				
TOTAL LIABILITIES	 	6,200.1 			5,881.3 		
	 				
Rate Matters (Note 4)	 				
Commitments and Contingencies (Note 5)	 				
	 				
MEMBER’S EQUITY	 	 		 	
Paid-in Capital		2,665.6 			2,480.6 		
Retained Earnings	 	1,833.0 			1,528.9 		
TOTAL MEMBER’S EQUITY	 	4,498.6 			4,009.5 		
	 				
TOTAL LIABILITIES AND MEMBER’S EQUITY	 	$	10,698.7 			$	9,890.8 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
74

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 	 	Nine Months Ended September 30,	
 	 	2020		2019	
OPERATING ACTIVITIES	 				
Net Income	 	$	309.1 			$	347.9 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:	 				
Depreciation and Amortization	 	176.4 			128.4 		
Deferred Income Taxes	 	65.4 			36.7 		
Allowance for Equity Funds Used During Construction	 	(54.9)			(61.1)		
Property Taxes	 	136.3 			110.7 		
	
Change in Other Noncurrent Assets	 	(1.5)			1.0 		
Change in Other Noncurrent Liabilities	 	19.5 			(3.8)		
Changes in Certain Components of Working Capital:	 			 	
Accounts Receivable, Net	 	(30.1)			(5.1)		
Materials and Supplies		0.2 			3.9 		
Accounts Payable	 	26.0 			4.1 		
Accrued Taxes, Net	 	(139.0)			(92.8)		
Accrued Interest	 	29.0 			23.8 		
Other Current Assets	 	9.1 			(1.0)		
Other Current Liabilities	 	(10.7)			(8.5)		
Net Cash Flows from Operating Activities	 	534.8 			484.2 		
	 				
INVESTING ACTIVITIES	 	 		 	
Construction Expenditures	 	(1,163.8)			(959.9)		
Change in Advances to Affiliates, Net	 	(21.3)			(178.3)		
Acquisitions of Assets	 	(3.6)			(7.6)		
	
Other Investing Activities	 	4.7 			12.0 		
Net Cash Flows Used for Investing Activities	 	(1,184.0)			(1,133.8)		
	 				
FINANCING ACTIVITIES	 			 	
Capital Contributions from Member	 	185.0 			— 		
Issuance of Long-term Debt – Nonaffiliated		519.4 			685.9 		
Change in Advances from Affiliates, Net	 	(50.2)			(36.3)		
Dividends Paid to AEP Transmission Holdco		(5.0)			— 		
	
Net Cash Flows from Financing Activities	 	649.2 			649.6 		
	 				
Net Change in Cash and Cash Equivalents	 	— 			— 		
Cash and Cash Equivalents at Beginning of Period	 	— 			— 		
Cash and Cash Equivalents at End of Period	 	$	— 			$	— 		
	 				
SUPPLEMENTARY INFORMATION	 	 		 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	63.3 			$	43.0 		
Net Cash Paid for Income Taxes	 	1.9 			29.8 		
Construction Expenditures Included in Current Liabilities as of September 30,	 	283.6 			315.1 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
75

APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
76

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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

 	Three Months Ended		Nine Months Ended	
 	September 30,		September 30,	
	2020		2019		2020		2019	
 	(in millions of KWhs)	
Retail:	 		 		 		 	
Residential	2,772 			2,728 			8,229 			8,401 		
Commercial	1,612 			1,721 			4,410 			4,812 		
Industrial	2,193 			2,487 			6,507 			7,180 		
Miscellaneous	203 			216 			585 			640 		
Total Retail	6,780 			7,152 			19,731 			21,033 		
								
Wholesale	1,187 			938 			2,894 			2,667 		
								
Total KWhs	7,967 			8,090 			22,625 			23,700 		

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

Summary of Heating and Cooling Degree Days

 	Three Months Ended		Nine Months Ended	
 	September 30,		September 30,	
	2020		2019		2020		2019	
 	(in degree days)	
Actual – Heating (a)	1 			— 			1,098 			1,295 		
Normal – Heating (b)	2 			3 			1,413 			1,407 		
								
Actual – Cooling (c)	988 			1,071 			1,354 			1,530 		
Normal – Cooling (b)	825 			815 			1,208 			1,194 		

(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.

77

Third Quarter of 2020 Compared to Third Quarter of 2019

Reconciliation of Third Quarter of 2019 to Third Quarter of 2020	
Net Income	
(in millions)	
	
Third Quarter of 2019		$	104.3 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		7.9 		
Margins from Off-system Sales		(1.2)		
Transmission Revenues		(3.1)		
Other Revenues		(1.3)		
Total Change in Gross Margin		2.3 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		13.6 		
Depreciation and Amortization		(4.5)		
Taxes Other Than Income Taxes		(2.1)		
Interest Income		0.3 		
	
Allowance for Equity Funds Used During Construction		1.9 		
Non-Service Cost Components of Net Periodic Benefit Cost		0.4 		
Interest Expense		(3.4)		
Total Change in Expenses and Other		6.2 		
 		 	
Income Tax Expense (Benefit)		3.8 		
 		 	
Third Quarter of 2020		$	116.6 		

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 $8 million primarily due to the following:
•An $8 million increase in deferred fuel primarily due to the timing of recoverable PJM expenses. This increase was offset in other expense items below.
•A $6 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $4 million increase due to the WVPSC approval of the Mitchell Plant surcharge effective January 2020.
These increases were partially offset by:
•An $8 million decrease in weather-related usage primarily driven by an 8% decrease in cooling degree days.
•A $3 million decrease in weather-normalized margins primarily in the commercial and industrial classes, partially offset in the residential class.
•Transmission Revenue decreased $3 million primarily due to an adjustment in July 2019 to the annual transmission formula rate true-up.

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

•Other Operation and Maintenance expenses decreased $14 million primarily due to the following:
•A $6 million decrease in distribution expense primarily due to storm and vegetation management expenses.
•A $3 million decrease in PJM expenses primarily related to the annual transmission formula rate true-up.
•A $3 million decrease in maintenance expense at various generation plants.
•A $2 million decrease in uncollectible accounts expenses.
These decreases were partially offset by:
•A $4 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $5 million primarily due to a higher depreciable base.
78

•Interest Expense increased $3 million primarily due to higher long-term debt balances.
•Income Tax Expense (Benefit) decreased $4 million primarily due the recognition of a discrete tax adjustment, which was primarily attributable to the filing of the 2019 Federal Income Tax return in the third quarter of 2020, and an increase in parent company loss benefit, partially offset by a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.

79

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020	
Net Income	
(in millions)	
	
Nine Months Ended September 30, 2019		$	293.5 		
 			
Changes in Gross Margin:		 	
Retail Margins		35.7 		
Margins from Off-system Sales		(3.2)		
Transmission Revenues		(8.9)		
Other Revenues		(1.3)		
Total Change in Gross Margin		22.3 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		72.7 		
Depreciation and Amortization		(17.7)		
Taxes Other Than Income Taxes		(5.7)		
Interest Income		(0.7)		
	
Allowance for Equity Funds Used During Construction		(1.0)		
Non-Service Cost Components of Net Periodic Benefit Cost		1.3 		
Interest Expense		(9.7)		
Total Change in Expenses and Other		39.2 		
 		 	
Income Tax Expense (Benefit)		(41.8)		
 		 	
Nine Months Ended September 30, 2020		$	313.2 		

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 $36 million primarily due to the following:
•A $30 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $28 million increase in deferred fuel primarily due to the timing of recoverable PJM expenses offset in line items below.
•A $12 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 $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.
•An $11 million increase due to a base rate increase in West Virginia.
These increases were partially offset by:
•A $41 million decrease in weather-related usage primarily driven by a 15% decrease in heating degree days and a 12% decrease in cooling degree days.
•A $16 million decrease in weather-normalized margins primarily in the commercial and industrial classes, partially offset in the residential class.
•Margins from Off-system Sales decreased $3 million due to weaker market prices for energy in the RTOs which caused a decrease in sales volume and margins.
•Transmission Revenues decreased $9 million primarily due to the following:
•A $13 million decrease from the annual transmission formula rate true-up.
This decrease was partially offset by:
•A $4 million increase from investment in transmission assets.

80

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

•Other Operation and Maintenance expenses decreased $73 million primarily due to the following:
•A $17 million decrease in transmission expenses primarily related to the annual transmission formula rate true-up.
•A $20 million decrease in maintenance expense at various generation plants.
•A $14 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 $10 million decrease in distribution expense primarily due to storm and vegetation management expenses.
•An $8 million decrease in employee-related expenses.
•Depreciation and Amortization expenses increased $18 million primarily due to a higher depreciable base and an increase in West Virginia depreciation rates beginning in March 2019. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $6 million primarily due to the following:
•A $3 million increase in property taxes due to additional investments in utility plant.
•A $3 million increase in state business and occupation taxes due to the reduction of the revitalization tax credit.
•Interest Expense increased $10 million primarily due to higher long-term debt balances.
•Income Tax Expense (Benefit) increased $42 million primarily due to a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.

81

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
 		2020		2019		2020		2019	
REVENUES		 		 		 		 	
Electric Generation, Transmission and Distribution		$	688.9 			$	696.7 			$	1,989.9 			$	2,041.3 		
Sales to AEP Affiliates		44.4 			56.6 			124.9 			154.6 		
Other Revenues		2.4 			2.2 			7.8 			8.2 		
TOTAL REVENUES		735.7 			755.5 			2,122.6 			2,204.1 		
									
EXPENSES		 		 		 		 	
Fuel and Other Consumables Used for Electric Generation		166.0 			177.3 			430.9 			521.8 		
Purchased Electricity for Resale		67.5 			78.3 			240.5 			253.4 		

Other Operation		136.3 			140.4 			379.1 			416.2 		
Maintenance		52.0 			61.5 			148.7 			184.3 		
Depreciation and Amortization		123.2 			118.7 			366.0 			348.3 		
Taxes Other Than Income Taxes		38.8 			36.7 			114.2 			108.5 		
TOTAL EXPENSES		583.8 			612.9 			1,679.4 			1,832.5 		
									
OPERATING INCOME		151.9 			142.6 			443.2 			371.6 		
									
Other Income (Expense):		 		 		 		 	
Interest Income		0.6 			0.3 			1.4 			2.1 		
	
Allowance for Equity Funds Used During Construction		6.7 			4.8 			11.5 			12.5 		
Non-Service Cost Components of Net Periodic Benefit Cost		4.7 			4.3 			14.1 			12.8 		
Interest Expense		(55.0)			(51.6)			(162.2)			(152.5)		
									
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)		108.9 			100.4 			308.0 			246.5 		
									
Income Tax Expense (Benefit)		(7.7)			(3.9)			(5.2)			(47.0)		
									
NET INCOME		$	116.6 			$	104.3 			$	313.2 			$	293.5 		
									
The common stock of APCo is wholly-owned by Parent.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
82

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
		2020		2019		2020		2019	
Net Income		$	116.6 			$	104.3 			$	313.2 			$	293.5 		
									
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES		 						 	
Cash Flow Hedges, Net of Tax of $0.1 and $(0.1) for the Three Months
   Ended September 30, 2020 and 2019, Respectively, and $(1.2) and
   $(0.2) for the Nine Months Ended September 30, 2020 and 2019,
   Respectively		0.6 			(0.3)			(4.4)			(0.7)		
Amortization of Pension and OPEB Deferred Costs, Net of Tax of
   $(0.3) and $(0.2) for the Three Months Ended September 30, 2020 and
   2019, Respectively, and $(0.8) and $(0.5) for the Nine Months Ended
   September 30, 2020 and 2019, Respectively		(0.9)			(0.6)			(2.8)			(1.9)		
									
TOTAL OTHER COMPREHENSIVE LOSS		(0.3)			(0.9)			(7.2)			(2.6)		
									
TOTAL COMPREHENSIVE INCOME		$	116.3 			$	103.4 			$	306.0 			$	290.9 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
83

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

		Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S
   EQUITY - DECEMBER 31, 2018		$	260.4 			$	1,828.7 			$	1,922.0 			$	(5.0)			$	4,006.1 		
											
Common Stock Dividends						(50.0)					(50.0)		
	
Net Income						133.7 					133.7 		
Other Comprehensive Loss								(0.8)			(0.8)		
TOTAL COMMON SHAREHOLDER’S
   EQUITY - MARCH 31, 2019		260.4 			1,828.7 			2,005.7 			(5.8)			4,089.0 		
											
Common Stock Dividends		 		 		(50.0)			 		(50.0)		
Net Income		 		 		55.5 			 		55.5 		
Other Comprehensive Loss		 		 		 		(0.9)			(0.9)		
TOTAL COMMON SHAREHOLDER’S
   EQUITY - JUNE 30, 2019		260.4 			1,828.7 			2,011.2 			(6.7)			4,093.6 		
											
Common Stock Dividends						(25.0)					(25.0)		
Net Income						104.3 					104.3 		
Other Comprehensive Loss								(0.9)			(0.9)		
TOTAL COMMON SHAREHOLDER’S
   EQUITY - SEPTEMBER 30, 2019		$	260.4 			$	1,828.7 			$	2,090.5 			$	(7.6)			$	4,172.0 		
											
TOTAL COMMON SHAREHOLDER’S
   EQUITY - DECEMBER 31, 2019		$	260.4 			$	1,828.7 			$	2,078.3 			$	5.0 			$	4,172.4 		
											
Common Stock Dividends						(50.0)					(50.0)		
	
Net Income						115.3 					115.3 		
Other Comprehensive Loss								(5.1)			(5.1)		
TOTAL COMMON SHAREHOLDER’S
   EQUITY - MARCH 31, 2020		260.4 			1,828.7 			2,143.6 			(0.1)			4,232.6 		
											
Common Stock Dividends						(50.0)					(50.0)		
	
Net Income						81.3 					81.3 		
Other Comprehensive Loss								(1.8)			(1.8)		
TOTAL COMMON SHAREHOLDER’S
   EQUITY - JUNE 30, 2020		260.4 			1,828.7 			2,174.9 			(1.9)			4,262.1 		
											
Common Stock Dividends		 		 		(50.0)			 		(50.0)		
Net Income		 		 		116.6 			 		116.6 		
Other Comprehensive Loss		 		 		 		(0.3)			(0.3)		
TOTAL COMMON SHAREHOLDER’S
   EQUITY - SEPTEMBER 30, 2020		$	260.4 			$	1,828.7 			$	2,241.5 			$	(2.2)			$	4,328.4 		
											
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	

84

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)

		September 30,		December 31,	
		2020		2019	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	3.9 			$	3.3 		
Restricted Cash for Securitized Funding		9.3 			23.5 		
Advances to Affiliates		159.5 			22.1 		
Accounts Receivable:		 		 	
Customers		136.6 			129.0 		
Affiliated Companies		60.2 			64.3 		
Accrued Unbilled Revenues		52.6 			59.7 		
Miscellaneous		0.2 			0.5 		
Allowance for Uncollectible Accounts		(3.4)			(2.6)		
Total Accounts Receivable		246.2 			250.9 		
Fuel		144.4 			149.7 		
Materials and Supplies		98.2 			105.2 		
Risk Management Assets		30.7 			39.4 		
	
Regulatory Asset for Under-Recovered Fuel Costs		3.7 			42.5 		
	
Prepayments and Other Current Assets		29.7 			64.0 		
TOTAL CURRENT ASSETS		725.6 			700.6 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Generation		6,615.9 			6,563.7 		
Transmission		3,811.4 			3,584.1 		
Distribution		4,348.8 			4,201.7 		
Other Property, Plant and Equipment		622.5 			571.3 		
Construction Work in Progress		539.9 			593.4 		
Total Property, Plant and Equipment		15,938.5 			15,514.2 		
Accumulated Depreciation and Amortization		4,652.7 			4,432.3 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		11,285.8 			11,081.9 		
					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		659.1 			457.2 		
Securitized Assets		216.2 			234.7 		
Long-term Risk Management Assets		0.1 			0.1 		
Operating Lease Assets		80.3 			78.5 		
Deferred Charges and Other Noncurrent Assets		190.9 			215.3 		
TOTAL OTHER NONCURRENT ASSETS		1,146.6 			985.8 		
					
TOTAL ASSETS		$	13,158.0 			$	12,768.3 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
85

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2020 and December 31, 2019
(Unaudited)

 		September 30,		December 31,	
 		2020		2019	
 		(in millions)	
CURRENT LIABILITIES		 		 	
Advances from Affiliates		$	4.3 			$	236.7 		
Accounts Payable:		 		 	
General		191.6 			307.8 		
Affiliated Companies		80.0 			92.5 		
Long-term Debt Due Within One Year – Nonaffiliated		518.3 			215.6 		
	
Risk Management Liabilities		5.6 			1.9 		
Customer Deposits		80.1 			85.8 		
	
Accrued Taxes		77.3 			99.6 		
Accrued Interest		73.8 			47.9 		
Obligations Under Operating Leases		14.7 			15.2 		
	
Other Current Liabilities		98.4 			123.0 		
TOTAL CURRENT LIABILITIES		1,144.1 			1,226.0 		
					
NONCURRENT LIABILITIES		 		 	
Long-term Debt – Nonaffiliated		4,315.0 			4,148.2 		
	
Long-term Risk Management Liabilities		0.2 			— 		
Deferred Income Taxes		1,716.5 			1,680.8 		
Regulatory Liabilities and Deferred Investment Tax Credits		1,195.8 			1,268.7 		
Asset Retirement Obligations		298.2 			102.1 		
Employee Benefits and Pension Obligations		38.2 			50.9 		
Obligations Under Operating Leases		66.1 			64.0 		
Deferred Credits and Other Noncurrent Liabilities		55.5 			55.2 		
TOTAL NONCURRENT LIABILITIES		7,685.5 			7,369.9 		
					
TOTAL LIABILITIES		8,829.6 			8,595.9 		
					
Rate Matters (Note 4)					
Commitments and Contingencies (Note 5)					
					
COMMON SHAREHOLDER’S EQUITY		 		 	
Common Stock – No Par Value:		 		 	
Authorized – 30,000,000 Shares		 		 	
Outstanding – 13,499,500 Shares		260.4 			260.4 		
Paid-in Capital		1,828.7 			1,828.7 		
Retained Earnings		2,241.5 			2,078.3 		
Accumulated Other Comprehensive Income (Loss)		(2.2)			5.0 		
TOTAL COMMON SHAREHOLDER’S EQUITY		4,328.4 			4,172.4 		
					
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY		$	13,158.0 			$	12,768.3 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
86

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Nine Months Ended September 30,	
 		2020		2019	
OPERATING ACTIVITIES		 		 	
Net Income		$	313.2 			$	293.5 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:		 		 	
Depreciation and Amortization		366.0 			348.3 		
Deferred Income Taxes		(28.2)			(101.9)		

Allowance for Equity Funds Used During Construction		(11.5)			(12.5)		
Mark-to-Market of Risk Management Contracts		8.0 			2.2 		
Pension Contributions to Qualified Plan Trust		(7.0)			— 		
	
Deferred Fuel Over/Under-Recovery, Net		38.8 			60.8 		
Change in Other Noncurrent Assets		5.4 			6.7 		
Change in Other Noncurrent Liabilities		(26.0)			(29.6)		
Changes in Certain Components of Working Capital:		 		 	
Accounts Receivable, Net		7.2 			61.7 		
Fuel, Materials and Supplies		12.4 			(49.2)		
Accounts Payable		(74.0)			40.1 		
Accrued Taxes, Net		1.9 			(30.2)		
Other Current Assets		10.1 			6.8 		
Other Current Liabilities		(9.7)			(25.1)		
Net Cash Flows from Operating Activities		606.6 			571.6 		
					
INVESTING ACTIVITIES		 		 	
Construction Expenditures		(566.6)			(607.1)		
	
Change in Advances to Affiliates, Net		(137.4)			0.3 		
	
Other Investing Activities		4.6 			22.8 		
Net Cash Flows Used for Investing Activities		(699.4)			(584.0)		
					
FINANCING ACTIVITIES		 		 	
Issuance of Long-term Debt – Nonaffiliated		557.2 			478.2 		
Change in Advances from Affiliates, Net		(232.4)			(165.2)		
Retirement of Long-term Debt – Nonaffiliated		(90.3)			(180.4)		

Principal Payments for Finance Lease Obligations		(5.6)			(5.0)		
Dividends Paid on Common Stock		(150.0)			(125.0)		
Other Financing Activities		0.3 			0.6 		
Net Cash Flows from Financing Activities		79.2 			3.2 		
					
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding		(13.6)			(9.2)		
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period		26.8 			29.8 		
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period		$	13.2 			$	20.6 		
					
SUPPLEMENTARY INFORMATION		 		 	
Cash Paid for Interest, Net of Capitalized Amounts		$	130.0 			$	120.6 		
Net Cash Paid (Received) for Income Taxes		(10.7)			58.7 		
Noncash Acquisitions Under Finance Leases		3.0 			7.1 		
Construction Expenditures Included in Current Liabilities as of September 30,		90.0 			134.2 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
87

INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
88

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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

 	Three Months Ended		Nine Months Ended	
 	September 30,		September 30,	
 	2020		2019		2020		2019	
 	(in millions of KWhs)	
Retail:	 		 		 		 	
Residential	1,531 			1,496 			4,230 			4,159 		
Commercial	1,219 			1,312 			3,362 			3,555 		
Industrial	1,849 			1,937 			5,324 			5,742 		
Miscellaneous	14 			16 			47 			49 		
Total Retail	4,613 			4,761 			12,963 			13,505 		
								
Wholesale	1,536 			2,398 			5,552 			6,842 		
								
Total KWhs	6,149 			7,159 			18,515 			20,347 		

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

Summary of Heating and Cooling Degree Days

 	Three Months Ended		Nine Months Ended	
 	September 30,		September 30,	
 	2020		2019		2020		2019	
 	(in degree days)	
Actual – Heating (a)	7 			— 			2,186 			2,456 		
Normal – Heating (b)	10 			11 			2,429 			2,412 		
								
Actual – Cooling (c)	637 			684 			923 			917 		
Normal – Cooling (b)	576 			573 			841 			836 		

(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.
89

Third Quarter of 2020 Compared to Third Quarter of 2019

Reconciliation of Third Quarter of 2019 to Third Quarter of 2020	
Net Income	
(in millions)	
			
Third Quarter of 2019		$	88.8 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		9.0 		
	
Margins from Off-system Sales		(0.3)		
Transmission Revenues		2.6 		
Other Revenues		(6.5)		
Total Change in Gross Margin		4.8 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		7.1 		
	
Depreciation and Amortization		(16.4)		
Taxes Other Than Income Taxes		(2.3)		
Other Income		(1.3)		

Non-Service Cost Components of Net Periodic Benefit Cost		(0.4)		
Interest Expense		1.9 		
Total Change in Expenses and Other		(11.4)		
 		 	
Income Tax Expense		(5.5)		
 		 	
Third Quarter of 2020		$	76.7 		

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 $9 million primarily due to the following:
•A $38 million increase primarily due to the Indiana and Michigan base rate cases and increases in rate riders. This increase was partially offset in other expense items below.
This increase was partially offset by:
•A $20 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract.
•A $6 million decrease in weather-related usage primarily due to a 7% decrease in cooling degree days.
•A $3 million decrease in weather-normalized retail margins.
•Transmission Revenues increased $3 million primarily due to a July 2019 adjustment to the annual transmission formula rate true-up.
•Other Revenues decreased $7 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.

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

•Other Operation and Maintenance expenses decreased $7 million primarily due to the following:
•A $10 million decrease in nonutility operation expenses primarily due to a decrease in RTD expenses. This decrease was partially offset in Other Revenues above.
•A $4 million decrease in steam generation expense primarily due to 2019 NSR Consent Decree modifications.
•A $4 million decrease in nuclear generation expenses primarily due to a decrease in maintenance activities.
•A $3 million decrease in administrative and general expenses primarily due to a decrease in rate case and insurance expenses.
These decreases were partially offset by:
•A $12 million increase in employee-related expenses.
•A $2 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
90

•Depreciation and Amortization expenses increased $16 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.
•Income Tax Expense increased $6 million primarily due to the recognition of a discrete tax adjustment, which was primarily attributable to the filing of the 2019 Federal Income Tax return in the third quarter of 2020, and an increase in state income tax expense.
91

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020	
Net Income	
(in millions)	
			
Nine Months Ended September 30, 2019		$	248.0 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		25.8 		
	
Margins from Off-system Sales		(0.3)		
Transmission Revenues		10.0 		
Other Revenues		(13.7)		
Total Change in Gross Margin		21.8 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		27.4 		
	
Depreciation and Amortization		(42.0)		
Taxes Other Than Income Taxes		(0.9)		
Other Income		(7.5)		

Non-Service Cost Components of Net Periodic Benefit Cost		(0.8)		
Interest Expense		0.2 		
Total Change in Expenses and Other		(23.6)		
 		 	
Income Tax Expense		(13.4)		
 		 	
Nine Months Ended September 30, 2020		$	232.8 		

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 $26 million primarily due to the following:
•A $72 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.
This increase was partially offset by:
•A $37 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract.
•An $8 million decrease in weather-related usage primarily due to an 11% decrease in heating degree days.
•A $6 million decrease in weather-normalized retail margins.
•Transmission Revenues increased $10 million primarily due to the following:
•A $6 million increase from the annual transmission formula rate true-up.
•A $4 million increase from investment in transmission assets. This increase was partially offset in Other Operation and Maintenance expenses below.
•Other Revenues decreased $14 million primarily due to a decrease in barging revenues by RTD. This decrease was partially offset in Other Operation and Maintenance expenses below.

92

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

•Other Operation and Maintenance expenses decreased $27 million primarily due to the following:
•An $18 million decrease in nonutility operation expenses primarily due to a decrease in RTD expenses. This decrease was partially offset in Other Revenues above.
•An $8 million decrease in distribution expenses primarily due to a decrease in vegetation management expenses.
•A $7 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2020.
•A $7 million decrease in Cook Plant refueling outage amortization expense primarily due to decreased costs of outages and various maintenance activities.
•A $4 million decrease in steam generation expense primarily due to 2019 NSR Consent Decree modifications.
These decreases were partially offset by:
•A $12 million increase in transmission expenses primarily due to a $21 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 Transmission Revenues above.
•A $5 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $42 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.
•Income Tax Expense increased $13 million primarily due to an increase in state income tax expense and a decrease in favorable flow-through tax benefits.
93

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
 		2020		2019		2020		2019	
REVENUES		 		 		 		 	
Electric Generation, Transmission and Distribution		$	570.1 			$	589.1 			$	1,648.4 			$	1,703.2 		
Sales to AEP Affiliates		1.3 			2.7 			9.1 			7.3 		
Other Revenues – Affiliated		14.1 			16.2 			42.4 			50.4 		
Other Revenues – Nonaffiliated		1.2 			3.1 			3.7 			7.6 		
TOTAL REVENUES		586.7 			611.1 			1,703.6 			1,768.5 		
									
EXPENSES		 		 		 		 	
Fuel and Other Consumables Used for Electric Generation		44.4 			61.2 			146.0 			161.2 		
Purchased Electricity for Resale		37.5 			44.8 			128.1 			163.3 		
Purchased Electricity from AEP Affiliates		55.9 			61.0 			135.8 			172.1 		
Other Operation		165.5 			172.7 			459.7 			467.7 		
Maintenance		51.0 			50.9 			144.4 			163.8 		
	
Depreciation and Amortization		104.5 			88.1 			303.6 			261.6 		
Taxes Other Than Income Taxes		27.4 			25.1 			79.5 			78.6 		
TOTAL EXPENSES		486.2 			503.8 			1,397.1 			1,468.3 		
									
OPERATING INCOME		100.5 			107.3 			306.5 			300.2 		
									
Other Income (Expense):		 		 		 		 	
Other Income		2.2 			3.5 			7.8 			15.3 		

Non-Service Cost Components of Net Periodic Benefit Cost		4.1 			4.5 			12.5 			13.3 		
Interest Expense		(26.9)			(28.8)			(85.7)			(85.9)		
									
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)		79.9 			86.5 			241.1 			242.9 		
									
Income Tax Expense (Benefit)		3.2 			(2.3)			8.3 			(5.1)		
									
NET INCOME		$	76.7 			$	88.8 			$	232.8 			$	248.0 		
									
The common stock of I&M is wholly-owned by Parent.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
94

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
		2020		2019		2020		2019	
Net Income		$	76.7 			$	88.8 			$	232.8 			$	248.0 		
									
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES		 				 		 	
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2020 and 2019, Respectively		0.4 			0.4 			1.2 			1.2 		
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2020 and 2019, Respectively		(0.1)			— 			(0.1)			(0.1)		
									
TOTAL OTHER COMPREHENSIVE INCOME		0.3 			0.4 			1.1 			1.1 		
									
TOTAL COMPREHENSIVE INCOME		$	77.0 			$	89.2 			$	233.9 			$	249.1 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
95

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

		Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2018		$	56.6 			$	980.9 			$	1,329.1 			$	(13.8)			$	2,352.8 		
											
Common Stock Dividends		 		 		(20.0)			 		(20.0)		
	
Net Income		 		 		98.9 			 		98.9 		
Other Comprehensive Income		 		 		 		0.4 			0.4 		
TOTAL COMMON SHAREHOLDER’S EQUITY - MARCH 31, 2019		56.6 			980.9 			1,408.0 			(13.4)			2,432.1 		
											
Common Stock Dividends						(20.0)					(20.0)		
Net Income						60.3 					60.3 		
Other Comprehensive Income								0.3 			0.3 		
TOTAL COMMON SHAREHOLDER’S EQUITY - JUNE 30, 2019		56.6 			980.9 			1,448.3 			(13.1)			2,472.7 		
											
Common Stock Dividends						(20.0)					(20.0)		
Net Income						88.8 					88.8 		
Other Comprehensive Income								0.4 			0.4 		
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2019		$	56.6 			$	980.9 			$	1,517.1 			$	(12.7)			$	2,541.9 		
		 		 		 		 		 	
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2019		$	56.6 			$	980.9 			$	1,518.5 			$	(11.6)			$	2,544.4 		
											
Common Stock Dividends						(21.3)					(21.3)		
ASU 2016-13 Adoption						0.4 					0.4 		
Net Income						92.3 					92.3 		
Other Comprehensive Income								0.4 			0.4 		
TOTAL COMMON SHAREHOLDER’S EQUITY - MARCH 31, 2020		56.6 			980.9 			1,589.9 			(11.2)			2,616.2 		
											
Common Stock Dividends		 		 		(21.2)			 		(21.2)		
Net Income		 		 		63.8 			 		63.8 		
Other Comprehensive Income		 		 		 		0.4 			0.4 		
TOTAL COMMON SHAREHOLDER’S EQUITY - JUNE 30, 2020		56.6 			980.9 			1,632.5 			(10.8)			2,659.2 		
											
Common Stock Dividends						(21.2)					(21.2)		
Net Income						76.7 					76.7 		
Other Comprehensive Income								0.3 			0.3 		
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2020		$	56.6 			$	980.9 			$	1,688.0 			$	(10.5)			$	2,715.0 		
											
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
96

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)

		September 30,		December 31,	
 		2020		2019	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	2.8 			$	2.0 		
Advances to Affiliates		13.3 			13.2 		
Accounts Receivable:		 		 	
Customers		34.7 			53.6 		
Affiliated Companies		43.5 			53.7 		
Accrued Unbilled Revenues		— 			2.5 		
Miscellaneous		0.9 			0.3 		
Allowance for Uncollectible Accounts		(0.3)			(0.6)		
Total Accounts Receivable		78.8 			109.5 		
Fuel		71.3 			56.2 		
Materials and Supplies		171.4 			171.3 		
Risk Management Assets		4.1 			9.8 		
Accrued Tax Benefits		29.8 			— 		
Regulatory Asset for Under-Recovered Fuel Costs		4.2 			3.0 		
Accrued Reimbursement of Spent Nuclear Fuel Costs		14.7 			24.0 		
	
Prepayments and Other Current Assets		17.0 			14.0 		
TOTAL CURRENT ASSETS		407.4 			403.0 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Generation		5,239.8 			5,099.7 		
Transmission		1,665.8 			1,641.8 		
Distribution		2,549.5 			2,437.6 		
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)		665.8 			632.6 		
Construction Work in Progress		383.3 			382.3 		
Total Property, Plant and Equipment		10,504.2 			10,194.0 		
Accumulated Depreciation, Depletion and Amortization		3,502.4 			3,294.3 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		7,001.8 			6,899.7 		
					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		450.2 			482.1 		
Spent Nuclear Fuel and Decommissioning Trusts		3,075.9 			2,975.7 		
Long-term Risk Management Assets		— 			0.1 		
Operating Lease Assets		228.8 			294.9 		
Deferred Charges and Other Noncurrent Assets		160.7 			181.9 		
TOTAL OTHER NONCURRENT ASSETS		3,915.6 			3,934.7 		
					
TOTAL ASSETS		$	11,324.8 			$	11,237.4 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
97

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2020 and December 31, 2019
(dollars in millions)
(Unaudited)

 		September 30,		December 31,	
 		2020		2019	
CURRENT LIABILITIES		 		 	
Advances from Affiliates		$	159.1 			$	114.4 		
Accounts Payable:		 		 	
General		133.3 			169.4 		
Affiliated Companies		79.7 			68.4 		
Long-term Debt Due Within One Year – Nonaffiliated
   (September 30, 2020 and December 31, 2019 Amounts Include $54.9 and $86.1,
   Respectively, Related to DCC Fuel)		348.7 			139.7 		
Risk Management Liabilities		0.2 			0.5 		
Customer Deposits		40.2 			39.4 		
Accrued Taxes		57.8 			112.4 		
Accrued Interest		19.9 			36.2 		
Obligations Under Operating Leases		83.8 			87.3 		
Regulatory Liability for Over-Recovered Fuel Costs		30.6 			6.1 		
Other Current Liabilities		91.0 			109.6 		
TOTAL CURRENT LIABILITIES		1,044.3 			883.4 		
					
NONCURRENT LIABILITIES		 		 	
Long-term Debt – Nonaffiliated		2,633.2 			2,910.5 		
Long-term Risk Management Liabilities		0.1 			— 		
Deferred Income Taxes		1,024.0 			979.7 		
Regulatory Liabilities and Deferred Investment Tax Credits		1,879.6 			1,891.4 		
Asset Retirement Obligations		1,796.1 			1,748.6 		
Obligations Under Operating Leases		165.4 			211.6 		
Deferred Credits and Other Noncurrent Liabilities		67.1 			67.8 		
TOTAL NONCURRENT LIABILITIES		7,565.5 			7,809.6 		
					
TOTAL LIABILITIES		8,609.8 			8,693.0 		
					
Rate Matters (Note 4)					
Commitments and Contingencies (Note 5)					
					
COMMON SHAREHOLDER’S EQUITY		 		 	
Common Stock – No Par Value:		 		 	
Authorized – 2,500,000 Shares		 		 	
Outstanding – 1,400,000 Shares		56.6 			56.6 		
Paid-in Capital		980.9 			980.9 		
Retained Earnings		1,688.0 			1,518.5 		
Accumulated Other Comprehensive Income (Loss)		(10.5)			(11.6)		
TOTAL COMMON SHAREHOLDER’S EQUITY		2,715.0 			2,544.4 		
					
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY		$	11,324.8 			$	11,237.4 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
98

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Nine Months Ended September 30,	
 		2020		2019	
OPERATING ACTIVITIES		 		 	
Net Income		$	232.8 			$	248.0 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:		 			
Depreciation and Amortization		303.6 			261.6 		
Rockport Plant, Unit 2 Operating Lease Amortization		51.9 			58.9 		
Deferred Income Taxes		(6.1)			(29.9)		
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net		21.3 			(11.6)		

Allowance for Equity Funds Used During Construction		(8.8)			(16.4)		
Mark-to-Market of Risk Management Contracts		5.6 			(1.6)		
Amortization of Nuclear Fuel		67.2 			71.6 		
Pension Contributions to Qualified Plan Trust		(6.4)			— 		
Deferred Fuel Over/Under-Recovery, Net		23.4 			(20.0)		
Change in Other Noncurrent Assets		40.8 			46.0 		
Change in Other Noncurrent Liabilities		30.2 			13.8 		
Changes in Certain Components of Working Capital:		 		 	
Accounts Receivable, Net		32.2 			50.5 		
Fuel, Materials and Supplies		(15.4)			(4.6)		
	
Accounts Payable		(0.9)			(7.3)		
	
Accrued Taxes, Net		(84.4)			(49.4)		
	
Rockport Plant, Unit 2 Operating Lease Payments		(36.9)			(36.9)		
Other Current Assets		6.6 			7.8 		
Other Current Liabilities		(59.1)			(49.7)		
Net Cash Flows from Operating Activities		597.6 			530.8 		
					
INVESTING ACTIVITIES		 		 	
Construction Expenditures		(409.1)			(431.7)		
Change in Advances to Affiliates, Net		(0.1)			(0.5)		
Purchases of Investment Securities		(1,290.0)			(915.7)		
Sales of Investment Securities		1,257.1 			871.4 		
Acquisitions of Nuclear Fuel		(68.4)			(91.9)		
	
Other Investing Activities		8.3 			10.5 		
Net Cash Flows Used for Investing Activities		(502.2)			(557.9)		
					
FINANCING ACTIVITIES		 		 	
Issuance of Long-term Debt – Nonaffiliated		— 			62.9 		
Change in Advances from Affiliates, Net		44.7 			101.3 		
Retirement of Long-term Debt – Nonaffiliated		(71.1)			(73.6)		
Principal Payments for Finance Lease Obligations		(4.8)			(4.0)		
Dividends Paid on Common Stock		(63.7)			(60.0)		
Other Financing Activities		0.3 			0.6 		
Net Cash Flows from (Used for) Financing Activities		(94.6)			27.2 		
					
Net Increase in Cash and Cash Equivalents		0.8 			0.1 		
Cash and Cash Equivalents at Beginning of Period		2.0 			2.4 		
Cash and Cash Equivalents at End of Period		$	2.8 			$	2.5 		
					
SUPPLEMENTARY INFORMATION		 		 	
Cash Paid for Interest, Net of Capitalized Amounts		$	97.5 			$	98.7 		
Net Cash Paid for Income Taxes		59.7 			40.2 		
Noncash Acquisitions Under Finance Leases		1.9 			8.1 		
Construction Expenditures Included in Current Liabilities as of September 30,		57.6 			76.3 		
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,		1.0 			— 		
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage		2.4 			— 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
99

OHIO POWER COMPANY AND SUBSIDIARIES

100

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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

 	Three Months Ended		Nine Months Ended	
 	September 30,		September 30,	
	2020		2019		2020		2019	
 	(in millions of KWhs)	
Retail:	 		 		 		 	
Residential	4,165 			4,120 			11,140 			11,034 		
Commercial	3,781 			4,067 			10,454 			11,072 		
Industrial	3,380 			3,689 			9,855 			10,936 		
Miscellaneous	22 			26 			82 			83 		
Total Retail (a)	11,348 			11,902 			31,531 			33,125 		
								
Wholesale (b)	502 			453 			1,347 			1,531 		
								
Total KWhs	11,850 			12,355 			32,878 			34,656 		

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

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

Summary of Heating and Cooling Degree Days

 	Three Months Ended		Nine Months Ended	
 	September 30,		September 30,	
	2020		2019		2020		2019	
 	(in degree days)	
Actual – Heating (a)	2 			— 			1,767 			2,006 		
Normal – Heating (b)	6 			6 			2,086 			2,072 		
								
Actual – Cooling (c)	809 			872 			1,126 			1,176 		
Normal – Cooling (b)	682 			672 			986 			973 		

(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.
101

Third Quarter of 2020 Compared to Third Quarter of 2019

Reconciliation of Third Quarter of 2019 to Third Quarter of 2020	
Net Income	
(in millions)	
			
Third Quarter of 2019		$	69.1 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		56.3 		
Margins from Off-system Sales		0.5 		
Transmission Revenues		4.4 		
Other Revenues		3.5 		
Total Change in Gross Margin		64.7 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(43.4)		
Depreciation and Amortization		(16.7)		
Taxes Other Than Income Taxes		(5.8)		
Interest Income		(0.4)		
	
Allowance for Equity Funds Used During Construction		(0.2)		
Non-Service Cost Components of Net Periodic Benefit Cost		0.1 		
Interest Expense		(1.5)		
Total Change in Expenses and Other		(67.9)		
 		 	
Income Tax Expense		(6.9)		
 		 	
Third Quarter of 2020		$	59.0 		

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 $56 million primarily due to the following:
•A $52 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
•An $18 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.
•A $5 million increase in revenues associated with the Universal Service Fund (USF). This increase was offset in Other Operation and Maintenance expenses below.
•A $3 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 $10 million decrease in usage primarily in the commercial and residential classes.
•A $6 million decrease due to the OVEC PPA rider which was replaced by the Legacy Generation Resource Rider (LGRR). This decrease was offset in Margins from Off-system Sales and Other Revenues below.
•A $3 million decrease in revenues associated with a vegetation management rider. This decrease was partially offset in Other Operation and Maintenance expenses below.
•Transmission Revenues increased $4 million primarily due to increased investment in transmission assets.
•Other Revenues increased $4 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.

102

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

•Other Operation and Maintenance expenses increased $43 million primarily due to the following:
•A $43 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase was offset in Gross Margin above.
•A $5 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.
These increases were partially offset by:
•A $5 million decrease in recoverable distribution expenses related to vegetation management. This decrease was offset in Retail Margins above.
•Depreciation and Amortization expenses increased $17 million primarily due to the following:
•A $9 million increase in recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•A $5 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•Taxes Other Than Income Taxes increased $6 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•Income Tax Expense increased $7 million primarily due to the recognition of a discrete tax adjustment which was primarily attributable to the filing of the 2019 Federal Income Tax return in the third quarter of 2020.
103

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020	
Net Income	
(in millions)	
			
Nine Months Ended September 30, 2019		$	247.7 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		6.0 		
Margins from Off-system Sales		7.3 		
Transmission Revenues		22.8 		
Other Revenues		12.2 		
Total Change in Gross Margin		48.3 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(28.3)		
Depreciation and Amortization		(27.6)		
Taxes Other Than Income Taxes		(10.9)		
Interest Income		(1.9)		
Carrying Costs Income		0.6 		
Allowance for Equity Funds Used During Construction		(4.8)		
Non-Service Cost Components of Net Periodic Benefit Cost		0.3 		
Interest Expense		(10.3)		
Total Change in Expenses and Other		(82.9)		
 		 	
Income Tax Expense		1.9 		
 		 	
Nine Months Ended September 30, 2020		$	215.0 		

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 $6 million primarily due to the following:
•A $74 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
•A $48 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.
•A $15 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.
•A $15 million increase in revenues associated with the USF. This increase was offset in Other Operation and Maintenance expenses 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 $23 million decrease in Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was partially offset in Depreciation and Amortization expenses below.
•A $21 million decrease due to the OVEC PPA rider which was replaced by the LGRR. This decrease was offset in Margins from Off-system Sales and Other Revenues below.
•A $17 million net decrease in margin for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.
•A $12 million decrease in usage primarily in the commercial class.
•A $9 million decrease in revenues associated with a vegetation management rider. This decrease was partially offset in Other Operation and Maintenance expenses below.
•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Other Operation and Maintenance expenses below.

104

•Margins from Off-system Sales increased $7 million primarily due to:
•An $18 million increase due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above.
This increase was partially offset by:
•A $12 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.
•Other Revenues increased $12 million primarily due to third-party LGRR 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 $28 million primarily due to the following:
•A $29 million increase in transmission expenses primarily due to a $57 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 Margin above.
•A $15 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.
These increases were partially offset by:
•A $6 million decrease in recoverable distribution expenses related to vegetation management. This decrease was offset in Retail Margins above.
•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 $28 million primarily due to the following:
•A $16 million increase in recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•A $14 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 in recoverable smart grid expense. This increase 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 $11 million primarily due to the following:
•A $16 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 $4 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 $5 million primarily due to adjustments that resulted from 2019 FERC audit findings and a decrease in AFUDC base.
•Interest Expense increased $10 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $2 million due to a decrease in pretax book income, partially offset by the recognition of a discrete tax adjustment.
105

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
 		2020		2019		2020		2019	
REVENUES		 		 		 		 	
Electricity, Transmission and Distribution		$	730.4 			$	698.6 			$	2,031.4 			$	2,127.4 		
Sales to AEP Affiliates		8.3 			9.0 			33.0 			18.2 		
Other Revenues		2.3 			3.0 			7.3 			8.4 		
TOTAL REVENUES		741.0 			710.6 			2,071.7 			2,154.0 		
									
EXPENSES		 		 		 		 	
Purchased Electricity for Resale		149.3 			158.3 			412.3 			454.0 		
Purchased Electricity from AEP Affiliates		24.1 			40.6 			96.8 			120.4 		
Amortization of Generation Deferrals		— 			8.8 			— 			65.3 		
Other Operation		244.6 			194.9 			608.5 			565.7 		
Maintenance		33.7 			40.0 			92.2 			106.7 		
Depreciation and Amortization		74.1 			57.4 			204.4 			176.8 		
Taxes Other Than Income Taxes		117.8 			112.0 			337.8 			326.9 		
TOTAL EXPENSES		643.6 			612.0 			1,752.0 			1,815.8 		
									
OPERATING INCOME		97.4 			98.6 			319.7 			338.2 		
									
Other Income (Expense):		 		 		 		 	
Interest Income		0.4 			0.8 			0.8 			2.7 		
Carrying Costs Income		0.3 			0.3 			1.3 			0.7 		
Allowance for Equity Funds Used During Construction		4.6 			4.8 			9.3 			14.1 		
Non-Service Cost Components of Net Periodic Benefit Cost		3.8 			3.7 			11.3 			11.0 		
Interest Expense		(29.4)			(27.9)			(88.4)			(78.1)		
									
INCOME BEFORE INCOME TAX EXPENSE		77.1 			80.3 			254.0 			288.6 		
									
Income Tax Expense		18.1 			11.2 			39.0 			40.9 		
									
NET INCOME		$	59.0 			$	69.1 			$	215.0 			$	247.7 		
									
The common stock of OPCo is wholly-owned by Parent.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
106

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2020		2019		2020		2019	
Net Income		$	59.0 			$	69.1 			$	215.0 			$	247.7 		
									
OTHER COMPREHENSIVE LOSS, NET OF TAXES		 		 		 		 	
Cash Flow Hedges, Net of Tax of $0 and $(0.1) for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0 and $(0.3) for the Nine Months Ended September 30, 2020 and 2019, Respectively		— 			(0.3)			— 			(1.0)		
									
TOTAL COMPREHENSIVE INCOME		$	59.0 			$	68.8 			$	215.0 			$	246.7 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
107

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

		Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018		$	321.2 			$	838.8 			$	1,136.4 			$	1.0 			$	2,297.4 		
											
Common Stock Dividends						(25.0)					(25.0)		
Net Income						128.0 					128.0 		
Other Comprehensive Loss								(0.3)			(0.3)		
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019		321.2 			838.8 			1,239.4 			0.7 			2,400.1 		
											
Common Stock Dividends		 		 		(60.0)			 		(60.0)		
Net Income		 		 		50.6 			 		50.6 		
Other Comprehensive Loss		 		 		 		(0.4)			(0.4)		
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019		321.2 			838.8 			1,230.0 			0.3 			2,390.3 		

Net Income						69.1 					69.1 		
Other Comprehensive Loss								(0.3)			(0.3)		
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019		$	321.2 			$	838.8 			$	1,299.1 			$	— 			$	2,459.1 		
		 		 		 		 		 	
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019		$	321.2 			$	838.8 			$	1,348.5 			$	— 			$	2,508.5 		
											
Common Stock Dividends						(21.9)					(21.9)		
ASU 2016-13 Adoption						0.3 					0.3 		
Net Income						75.1 					75.1 		
	
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020		321.2 			838.8 			1,402.0 			— 			2,562.0 		
											
Common Stock Dividends		 		 		(21.9)			 		(21.9)		
Net Income		 		 		80.9 			 		80.9 		
	
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2020		321.2 			838.8 			1,461.0 			— 			2,621.0 		
											
Common Stock Dividends						(21.8)					(21.8)		
Net Income						59.0 					59.0 		
	
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2020		$	321.2 			$	838.8 			$	1,498.2 			$	— 			$	2,658.2 		
											
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
108

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)

 		September 30,		December 31,	
 		2020		2019	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	6.6 			$	3.7 		
	
Accounts Receivable:		 		 	
Customers		18.4 			53.0 		
Affiliated Companies		61.0 			59.3 		
Accrued Unbilled Revenues		20.1 			20.3 		
Miscellaneous		3.9 			0.5 		
Allowance for Uncollectible Accounts		(0.7)			(0.7)		
Total Accounts Receivable		102.7 			132.4 		
Materials and Supplies		67.0 			52.3 		
Renewable Energy Credits		28.7 			30.9 		
	
Accrued Tax Benefits		4.3 			11.5 		
	
Prepayments and Other Current Assets		13.2 			7.7 		
TOTAL CURRENT ASSETS		222.5 			238.5 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Transmission		2,768.1 			2,686.3 		
Distribution		5,545.8 			5,323.5 		
Other Property, Plant and Equipment		882.4 			765.8 		
Construction Work in Progress		455.9 			394.4 		
Total Property, Plant and Equipment		9,652.2 			9,170.0 		
Accumulated Depreciation and Amortization		2,350.1 			2,263.0 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		7,302.1 			6,907.0 		
					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		401.7 			351.8 		
	
Deferred Charges and Other Noncurrent Assets		340.6 			546.3 		
TOTAL OTHER NONCURRENT ASSETS		742.3 			898.1 		
					
TOTAL ASSETS		$	8,266.9 			$	8,043.6 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
109

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2020 and December 31, 2019
(dollars in millions)
(Unaudited)

 		September 30,		December 31,	
 		2020		2019	
CURRENT LIABILITIES		 		 	
Advances from Affiliates		$	215.9 			$	131.0 		
Accounts Payable:		 		 	
General		184.5 			233.7 		
Affiliated Companies		90.7 			103.6 		
Long-term Debt Due Within One Year – Nonaffiliated		0.1 			0.1 		
Risk Management Liabilities		8.2 			7.3 		
Customer Deposits		58.2 			70.6 		
Accrued Taxes		314.5 			587.9 		
	
Obligations Under Operating Leases		12.5 			12.5 		
Other Current Liabilities		141.1 			151.2 		
TOTAL CURRENT LIABILITIES		1,025.7 			1,297.9 		
					
NONCURRENT LIABILITIES		 		 	
Long-term Debt – Nonaffiliated		2,429.8 			2,081.9 		
Long-term Risk Management Liabilities		105.1 			96.3 		
Deferred Income Taxes		904.6 			849.4 		
Regulatory Liabilities and Deferred Investment Tax Credits		1,018.5 			1,090.9 		
	
Obligations Under Operating Leases		76.7 			76.0 		
Deferred Credits and Other Noncurrent Liabilities		48.3 			42.7 		
TOTAL NONCURRENT LIABILITIES		4,583.0 			4,237.2 		
					
TOTAL LIABILITIES		5,608.7 			5,535.1 		
					
Rate Matters (Note 4)					
Commitments and Contingencies (Note 5)					
					
COMMON SHAREHOLDER’S EQUITY		 		 	
Common Stock –No Par Value:		 		 	
Authorized – 40,000,000 Shares		 		 	
Outstanding – 27,952,473 Shares		321.2 			321.2 		
Paid-in Capital		838.8 			838.8 		
Retained Earnings		1,498.2 			1,348.5 		
	
TOTAL COMMON SHAREHOLDER’S EQUITY		2,658.2 			2,508.5 		
					
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY		$	8,266.9 			$	8,043.6 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
110

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Nine Months Ended September 30,	
 		2020		2019	
OPERATING ACTIVITIES		 		 	
Net Income		$	215.0 			$	247.7 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:		 		 	
Depreciation and Amortization		204.4 			176.8 		
Amortization of Generation Deferrals		— 			65.3 		
Deferred Income Taxes		35.6 			16.8 		
	
Allowance for Equity Funds Used During Construction		(9.3)			(14.1)		
Mark-to-Market of Risk Management Contracts		9.7 			13.3 		
	
Property Taxes		225.1 			197.7 		
Refund of Global Settlement		— 			(12.4)		
Reversal of Regulatory Provision		— 			(56.2)		
	
Change in Other Noncurrent Assets		(93.8)			(47.5)		
Change in Other Noncurrent Liabilities		(58.3)			(51.1)		
Changes in Certain Components of Working Capital:		 		 	
Accounts Receivable, Net		33.4 			90.0 		
Materials and Supplies		(19.8)			(9.6)		
Accounts Payable		(19.9)			(12.3)		
Accrued Taxes, Net		(266.2)			(245.9)		
Other Current Assets		(2.5)			(9.0)		
Other Current Liabilities		(23.3)			(40.0)		
Net Cash Flows from Operating Activities		230.1 			309.5 		
					
INVESTING ACTIVITIES		 		 	
Construction Expenditures		(604.6)			(570.6)		
	
Other Investing Activities		14.1 			20.0 		
Net Cash Flows Used for Investing Activities		(590.5)			(550.6)		
					
FINANCING ACTIVITIES		 		 	
Issuance of Long-term Debt – Nonaffiliated		347.0 			444.3 		
Change in Advances from Affiliates, Net		84.9 			(96.5)		
Retirement of Long-term Debt – Nonaffiliated		(0.1)			(48.0)		
Principal Payments for Finance Lease Obligations		(3.5)			(2.6)		
Dividends Paid on Common Stock		(65.6)			(85.0)		
Other Financing Activities		0.6 			1.1 		
Net Cash Flows from Financing Activities		363.3 			213.3 		
					
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding		2.9 			(27.8)		
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period		3.7 			32.5 		
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period		$	6.6 			$	4.7 		
					
SUPPLEMENTARY INFORMATION		 		 	
Cash Paid for Interest, Net of Capitalized Amounts		$	69.7 			$	61.3 		
Net Cash Paid (Received) for Income Taxes		(6.0)			25.7 		
Noncash Acquisitions Under Finance Leases		5.2 			8.6 		
Construction Expenditures Included in Current Liabilities as of September 30,		75.9 			99.9 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
111

PUBLIC SERVICE COMPANY OF OKLAHOMA
112

PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

 	Three Months Ended		Nine Months Ended	
 	September 30,		September 30,	
	2020		2019		2020		2019	
 	(in millions of KWhs)	
Retail:	 		 		 		 	
Residential	2,019 			2,172 			4,838 			4,981 		
Commercial	1,358 			1,497 			3,549 			3,818 		
Industrial	1,461 			1,642 			4,299 			4,665 		
Miscellaneous	347 			378 			912 			950 		
Total Retail	5,185 			5,689 			13,598 			14,414 		
								
Wholesale	130 			224 			261 			617 		
								
Total KWhs	5,315 			5,913 			13,859 			15,031 		

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

Summary of Heating and Cooling Degree Days

 	Three Months Ended		Nine Months Ended	
 	September 30,		September 30,	
	2020		2019		2020		2019	
 	(in degree days)	
Actual – Heating (a)	1 			— 			874 			1,199 		
Normal – Heating (b)	1 			1 			1,078 			1,077 		
								
Actual – Cooling (c)	1,274 			1,593 			1,979 			2,206 		
Normal – Cooling (b)	1,412 			1,397 			2,088 			2,072 		

(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.
113

Third Quarter of 2020 Compared to Third Quarter of 2019

Reconciliation of Third Quarter of 2019 to Third Quarter of 2020	
Net Income	
(in millions)	
			
Third Quarter of 2019		$	100.3 		
			
Changes in Gross Margin:			
Retail Margins (a)		(20.7)		
Margins from Off-system Sales		(1.3)		
Transmission Revenues		(0.5)		
Other Revenues		(0.2)		
Total Change in Gross Margin		(22.7)		
			
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(2.5)		
Depreciation and Amortization		(1.0)		
Taxes Other Than Income Taxes		(1.0)		
Interest Income		(0.4)		
	
Allowance for Equity Funds Used During Construction		0.5 		

Interest Expense		1.5 		
Total Change in Expenses and Other		(2.9)		
 		 	
Income Tax Expense		5.6 		
 		 	
Third Quarter of 2020		$	80.3 		

(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 $21 million primarily due to the following:
•An $18 million decrease in weather-related usage due to a 20% decrease in cooling degree-days.
•A $4 million decrease in revenue from rate riders. This decrease 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 increased $3 million primarily due to the following:
•A $4 million increase in transmission expenses due to an increase in recoverable SPP expenses. This increase was partially offset in Retail Margins above.
•A $2 million increase in customer-related expenses primarily related to energy efficiency programs. This increase was partially offset in Retail Margins above.
These increases were partially offset by:
•A $4 million decrease in distribution expenses.
•Income Tax Expense decreased $6 million primarily due to a decrease in pretax book income.
114

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020	
Net Income	
(in millions)	
			
Nine Months Ended September 30, 2019		$	148.4 		
 		 	
Changes in Gross Margin:		 	
Retail Margins (a)		(15.1)		
Margin from Off-system Sales		(1.7)		
Transmission Revenues		(0.8)		
Other Revenues		3.4 		
Total Change in Gross Margin		(14.2)		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(21.3)		
Depreciation and Amortization		(4.4)		
Taxes Other Than Income Taxes		(2.8)		
Interest Income		(0.5)		
	
Allowance for Equity Funds Used During Construction		1.7 		

Interest Expense		4.4 		
Total Change in Expenses and Other		(22.9)		
 		 	
Income Tax Expense		5.1 		
 		 	
Nine Months Ended September 30, 2020		$	116.4 		
(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 $15 million primarily due to the following:
•A $15 million decrease in weather-related usage due to a 10% decrease in cooling degree-days.
•A $10 million decrease in revenue from rate riders. This decrease was partially offset in other expense items below.
•A $7 million decrease due to customer refunds related to Tax Reform. This decrease is partially offset in Income Tax Expense below.
These decreases were partially offset by:
•A $10 million increase due to new base rates implemented in April 2019.
•A $7 million increase in weather-normalized margins.
•Other Revenues increased $3 million primarily due to business development revenue. This increase was offset in other expense items below.

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

•Other Operation and Maintenance expenses increased $21 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 $5 million increase in customer-related expenses primarily related to energy efficiency programs. This increase was partially offset in Retail Margins above.
•A $4 million increase in business development expenses. This increase was partially offset in Other Revenues above.
•A $4 million increase in maintenance of overhead lines for non-storm related expenses.
These increases were partially offset by:
•A $7 million decrease in expenses at various generation plants.
•A $5 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs.
115

•Depreciation and Amortization expenses increased $4 million primarily due to a higher depreciable base.
•Interest Expense decreased $4 million primarily due to lower interest rates on long-term debt.
•Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income, partially offset by a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset in Retail Margins above.
116

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
 		2020		2019		2020		2019	
REVENUES		 		 		 		 	
Electric Generation, Transmission and Distribution		$	379.8 			$	490.5 			$	976.3 			$	1,164.3 		
Sales to AEP Affiliates		1.4 			1.3 			3.8 			5.0 		
Other Revenues		1.0 			1.2 			8.0 			4.6 		
TOTAL REVENUES		382.2 			493.0 			988.1 			1,173.9 		
									
EXPENSES		 		 		 		 	
Fuel and Other Consumables Used for Electric Generation		20.9 			98.4 			36.2 			181.2 		
Purchased Electricity for Resale		104.7 			115.3 			314.1 			340.7 		
	
Other Operation		91.7 			87.6 			248.5 			226.0 		
Maintenance		19.9 			21.5 			68.9 			70.1 		
Depreciation and Amortization		40.1 			39.1 			129.8 			125.4 		
Taxes Other Than Income Taxes		12.1 			11.1 			35.8 			33.0 		
TOTAL EXPENSES		289.4 			373.0 			833.3 			976.4 		
									
OPERATING INCOME		92.8 			120.0 			154.8 			197.5 		
									
Other Income (Expense):		 		 		 		 	
Interest Income		— 			0.4 			0.1 			0.6 		
	
Allowance for Equity Funds Used During Construction		1.3 			0.8 			3.2 			1.5 		
	
Non-Service Cost Components of Net Periodic Benefit Cost		2.1 			2.1 			6.3 			6.3 		
Interest Expense		(14.6)			(16.1)			(45.9)			(50.3)		
									
INCOME BEFORE INCOME TAX EXPENSE		81.6 			107.2 			118.5 			155.6 		
									
Income Tax Expense		1.3 			6.9 			2.1 			7.2 		
									
NET INCOME		$	80.3 			$	100.3 			$	116.4 			$	148.4 		
									
The common stock of PSO is wholly-owned by Parent.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
117

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
		2020		2019		2020		2019	
Net Income		$	80.3 			$	100.3 			$	116.4 			$	148.4 		
									
OTHER COMPREHENSIVE LOSS, NET OF TAXES		 		 		 		 	
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $(0.2) and $(0.2) for the Nine Months Ended September 30, 2020 and 2019, Respectively.		(0.3)			(0.2)			(0.8)			(0.7)		
		 		 		 		 	
TOTAL COMPREHENSIVE INCOME		$	80.0 			$	100.1 			$	115.6 			$	147.7 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
118

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

		Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018		$	157.2 			$	364.0 			$	724.7 			$	2.1 			$	1,248.0 		
											
Common Stock Dividends						(11.3)					(11.3)		
	
Net Income						6.2 					6.2 		
Other Comprehensive Loss								(0.2)			(0.2)		
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019		157.2 			364.0 			719.6 			1.9 			1,242.7 		

Net Income		 		 		41.9 			 		41.9 		
Other Comprehensive Loss		 		 		 		(0.3)			(0.3)		
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019		157.2 			364.0 			761.5 			1.6 			1,284.3 		

Net Income						100.3 					100.3 		
Other Comprehensive Loss								(0.2)			(0.2)		
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019		$	157.2 			$	364.0 			$	861.8 			$	1.4 			$	1,384.4 		
											
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019		$	157.2 			$	364.0 			$	851.0 			$	1.1 			$	1,373.3 		

ASU 2016-13 Adoption						0.3 					0.3 		
Net Loss						(10.3)					(10.3)		
Other Comprehensive Loss								(0.2)			(0.2)		
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020		157.2 			364.0 			841.0 			0.9 			1,363.1 		

Net Income		 		 		46.4 			 		46.4 		
Other Comprehensive Loss		 		 		 		(0.3)			(0.3)		
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2020		157.2 			364.0 			887.4 			0.6 			1,409.2 		

Net Income						80.3 					80.3 		
Other Comprehensive Loss								(0.3)			(0.3)		
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2020		$	157.2 			$	364.0 			$	967.7 			$	0.3 			$	1,489.2 		
											
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
119

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)

 		September 30,		December 31,	
 		2020		2019	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	3.0 			$	1.5 		
Advances to Affiliates		— 			38.8 		
Accounts Receivable:		 		 	
Customers		25.2 			28.9 		
Affiliated Companies		27.1 			20.6 		
Miscellaneous		3.1 			0.6 		
Allowance for Uncollectible Accounts		— 			(0.3)		
Total Accounts Receivable		55.4 			49.8 		
Fuel		22.8 			12.2 		
Materials and Supplies		53.4 			46.8 		
Risk Management Assets		16.6 			15.8 		
	
Accrued Tax Benefits		0.6 			11.3 		
	
Prepayments and Other Current Assets		11.8 			12.0 		
TOTAL CURRENT ASSETS		163.6 			188.2 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Generation		1,474.1 			1,574.6 		
Transmission		981.2 			948.5 		
Distribution		2,799.5 			2,684.8 		
Other Property, Plant and Equipment		381.8 			342.1 		
Construction Work in Progress		147.2 			133.4 		
Total Property, Plant and Equipment		5,783.8 			5,683.4 		
Accumulated Depreciation and Amortization		1,578.3 			1,580.1 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		4,205.5 			4,103.3 		
					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		388.9 			375.2 		
	
Employee Benefits and Pension Assets		44.8 			43.9 		
Operating Lease Assets		40.5 			36.8 		
Deferred Charges and Other Noncurrent Assets		15.9 			4.1 		
TOTAL OTHER NONCURRENT ASSETS		490.1 			460.0 		
					
TOTAL ASSETS		$	4,859.2 			$	4,751.5 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
120

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2020 and December 31, 2019
(Unaudited)

 		September 30,		December 31,	
 		2020		2019	
 		(in millions)	
CURRENT LIABILITIES		 		 	
Advances from Affiliates		$	77.8 			$	— 		
Accounts Payable:		 		 	
General		106.7 			134.3 		
Affiliated Companies		41.0 			59.3 		
Long-term Debt Due Within One Year – Nonaffiliated		250.5 			13.2 		
Risk Management Liabilities		0.5 			— 		
Customer Deposits		56.2 			58.9 		
Accrued Taxes		49.1 			22.9 		
	
Obligations Under Operating Leases		6.2 			5.8 		
Regulatory Liability for Over-Recovered Fuel Costs		17.3 			63.9 		
	
Other Current Liabilities		72.8 			87.5 		
TOTAL CURRENT LIABILITIES		678.1 			445.8 		
					
NONCURRENT LIABILITIES		 		 	
Long-term Debt – Nonaffiliated		1,123.2 			1,373.0 		
	
Deferred Income Taxes		649.6 			628.3 		
Regulatory Liabilities and Deferred Investment Tax Credits		816.4 			837.2 		
Asset Retirement Obligations		46.4 			44.5 		
	
Obligations Under Operating Leases		34.3 			31.0 		
Deferred Credits and Other Noncurrent Liabilities		22.0 			18.4 		
TOTAL NONCURRENT LIABILITIES		2,691.9 			2,932.4 		
					
TOTAL LIABILITIES		3,370.0 			3,378.2 		
					
Rate Matters (Note 4)					
Commitments and Contingencies (Note 5)					
					
COMMON SHAREHOLDER’S EQUITY		 		 	
Common Stock – Par Value – $15 Per Share:		 		 	
Authorized – 11,000,000 Shares		 		 	
Issued – 10,482,000 Shares		 		 	
Outstanding – 9,013,000 Shares		157.2 			157.2 		
Paid-in Capital		364.0 			364.0 		
Retained Earnings		967.7 			851.0 		
Accumulated Other Comprehensive Income (Loss)		0.3 			1.1 		
TOTAL COMMON SHAREHOLDER’S EQUITY		1,489.2 			1,373.3 		
					
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY		$	4,859.2 			$	4,751.5 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
121

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Nine Months Ended September 30,	
 		2020		2019	
OPERATING ACTIVITIES		 		 	
Net Income		$	116.4 			$	148.4 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:		 		 	
Depreciation and Amortization		129.8 			125.4 		
Deferred Income Taxes		(3.2)			(9.7)		
	
Allowance for Equity Funds Used During Construction		(3.2)			(1.5)		
Mark-to-Market of Risk Management Contracts		(0.3)			(12.0)		
	
Property Taxes		(10.6)			(9.6)		
Deferred Fuel Over/Under-Recovery, Net		(46.6)			49.8 		
	
Change in Other Noncurrent Assets		(7.2)			4.6 		
Change in Other Noncurrent Liabilities		6.1 			(0.2)		
Changes in Certain Components of Working Capital:		 		 	
Accounts Receivable, Net		(5.6)			9.1 		
Fuel, Materials and Supplies		(17.2)			(1.9)		
Accounts Payable		(26.1)			(5.8)		
Accrued Taxes, Net		36.9 			19.0 		
Other Current Assets		(0.1)			(2.4)		
Other Current Liabilities		(16.4)			1.1 		
Net Cash Flows from Operating Activities		152.7 			314.3 		
					
INVESTING ACTIVITIES		 		 	
Construction Expenditures		(256.4)			(198.7)		
Change in Advances to Affiliates, Net		38.8 			(95.1)		
Other Investing Activities		3.9 			2.1 		
Net Cash Flows Used for Investing Activities		(213.7)			(291.7)		
					
FINANCING ACTIVITIES		 		 	
Issuance of Long-term Debt – Nonaffiliated		— 			349.8 		
Change in Advances from Affiliates, Net		77.8 			(105.5)		
Retirement of Long-term Debt – Nonaffiliated		(13.0)			(250.4)		
	
Principal Payments for Finance Lease Obligations		(2.7)			(2.2)		
Dividends Paid on Common Stock		— 			(11.3)		
Other Financing Activities		0.4 			(2.1)		
Net Cash Flows from (Used for) Financing Activities		62.5 			(21.7)		
					
Net Increase in Cash and Cash Equivalents		1.5 			0.9 		
Cash and Cash Equivalents at Beginning of Period		1.5 			2.0 		
Cash and Cash Equivalents at End of Period		$	3.0 			$	2.9 		
					
SUPPLEMENTARY INFORMATION		 		 	
Cash Paid for Interest, Net of Capitalized Amounts		$	45.5 			$	46.5 		
Net Cash Paid (Received) for Income Taxes		(9.5)			16.0 		
Noncash Acquisitions Under Finance Leases		3.0 			3.4 		
Construction Expenditures Included in Current Liabilities as of September 30,		23.5 			31.5 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
122

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

123

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales

	Three Months Ended		Nine Months Ended	
 	September 30,		September 30,	
 	2020		2019		2020		2019	
 	(in millions of KWhs)	
Retail:	 		 		 		 	
Residential	1,950 			2,071 			4,702 			4,896 		
Commercial	1,552 			1,746 			4,016 			4,430 		
Industrial	1,185 			1,414 			3,614 			4,020 		
Miscellaneous	19 			19 			59 			59 		
Total Retail	4,706 			5,250 			12,391 			13,405 		
								
Wholesale	1,571 			1,831 			4,081 			5,317 		
								
Total KWhs	6,277 			7,081 			16,472 			18,722 		

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

Summary of Heating and Cooling Degree Days

	Three Months Ended		Nine Months Ended	
 	September 30,		September 30,	
 	2020		2019		2020		2019	
 	(in degree days)	
Actual – Heating (a)	— 			— 			522 			732 		
Normal – Heating (b)	1 			1 			724 			725 		
								
Actual – Cooling (c)	1,308 			1,552 			2,051 			2,263 		
Normal – Cooling (b)	1,420 			1,408 			2,200 			2,187 		

(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.

124

Third Quarter of 2020 Compared to Third Quarter of 2019

Reconciliation of Third Quarter of 2019 to Third Quarter of 2020	
Earnings Attributable to SWEPCo Common Shareholder	
(in millions)	
			
Third Quarter of 2019		$	110.5 		
 		 	
Changes in Gross Margin:		 	
Retail Margins (a)		(8.9)		
Margins from Off-system Sales		(0.3)		
Transmission Revenues		2.5 		
Other Revenues		(0.6)		
Total Change in Gross Margin		(7.3)		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		0.3 		
	
Depreciation and Amortization		(5.3)		
Taxes Other Than Income Taxes		(0.5)		
	
Allowance for Equity Funds Used During Construction		1.8 		

Interest Expense		(0.1)		
Total Change in Expenses and Other		(3.8)		
 		 	
Income Tax Expense		(11.5)		
Equity Earnings of Unconsolidated Subsidiary		(0.1)		
Net Income Attributable to Noncontrolling Interest		0.1 		
 		 	
Third Quarter of 2020		$	87.9 		

(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 $9 million primarily due to the following:
•A $17 million decrease in weather-related usage primarily due to a 16% decrease in cooling degree days.
•An $8 million decrease in weather-normalized margins.
These decreases were partially offset by:
•A $14 million increase primarily due to a base rate revenue increase in Arkansas.

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

•Depreciation and Amortization expenses increased $5 million primarily due to a higher depreciable base and an increase in Arkansas depreciation rates beginning in January 2020. This increase was partially offset in Retail Margins above.
•Income Tax Expense increased $12 million primarily due to a decrease in amortization of Excess ADIT, partially offset by a decrease in pretax book income. The decrease in amortization of Excess ADIT was partially offset in Retail Margins above.
125

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020	
Earnings Attributable to SWEPCo Common Shareholder	
(in millions)	
			
Nine Months Ended September 30, 2019		$	144.5 		
 		 	
Changes in Gross Margin:		 	
Retail Margins (a)		4.4 		
Margins from Off-system Sales		(2.5)		
Transmission Revenues		55.8 		
Other Revenues		(2.4)		
Total Change in Gross Margin		55.3 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(9.7)		
	
Depreciation and Amortization		(16.8)		
Taxes Other Than Income Taxes		(1.0)		
Interest Income		(0.3)		
Allowance for Equity Funds Used During Construction		1.2 		
Non-Service Cost Components of Net Periodic Benefit Cost		(0.1)		
	
Interest Expense		0.3 		
Total Change in Expenses and Other		(26.4)		
 		 	
Income Tax Expense		(12.5)		
Equity Earnings of Unconsolidated Subsidiary		(0.1)		
Net Income Attributable to Noncontrolling Interest		1.0 		
 		 	
Nine Months Ended September 30, 2020		$	161.8 		

(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 increased $4 million primarily due to the following:
•A $35 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.
•A $6 million increase in municipal and cooperative revenues primarily due to formula rate true-ups.
•A $4 million increase in recoverable fuel costs primarily due to timing of recovery.
These increases were partially offset by:
•A $23 million decrease in weather-related usage primarily due to a 9% decrease in cooling degree days and a 29% decrease in heating degree days.
•A $17 million decrease in weather-normalized margins.
•Transmission Revenues increased $56 million primarily due to the following:
•A $36 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 $14 million increase due to continued investment in transmission projects.

126

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

•Other Operation and Maintenance expenses increased $10 million primarily due to the following:
•A $20 million increase in SPP transmission expenses primarily due to the annual transmission formula rate true-up. This increase was offset in Transmission Revenues above.
•A $9 million increase in administrative and general expenses and employee-related expenses.
These increases were partially offset by:
•An $8 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs.
•A $6 million decrease in generation plant maintenance expenses.
•A $4 million decrease in customer-related expenses primarily in energy efficiency programs. This decrease is offset in Retail Margins above.
•Depreciation and Amortization expenses increased $17 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 $13 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income. The decrease in amortization of Excess ADIT is partially offset in Retail Margins above.
127

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
 		2020		2019		2020		2019	
REVENUES		 		 		 		 	
Electric Generation, Transmission and Distribution		$	505.7 			$	536.5 			$	1,284.3 			$	1,344.8 		
Sales to AEP Affiliates		8.5 			8.8 			33.5 			21.6 		
Provision for Refund – Affiliated		2.4 			(0.1)			(2.0)			(25.3)		
Other Revenues		0.7 			0.3 			2.4 			1.0 		
TOTAL REVENUES		517.3 			545.5 			1,318.2 			1,342.1 		
									
EXPENSES		 		 		 		 	
Fuel and Other Consumables Used for Electric Generation		131.7 			148.8 			306.4 			400.2 		
Purchased Electricity for Resale		41.0 			44.8 			125.1 			110.5 		
	
Other Operation		96.8 			91.9 			259.0 			242.4 		
Maintenance		30.7 			35.9 			97.2 			104.1 		
	
Depreciation and Amortization		68.5 			63.2 			203.9 			187.1 		
Taxes Other Than Income Taxes		26.7 			26.2 			77.0 			76.0 		
TOTAL EXPENSES		395.4 			410.8 			1,068.6 			1,120.3 		
									
OPERATING INCOME		121.9 			134.7 			249.6 			221.8 		
									
Other Income (Expense):		 		 				 	
Interest Income		0.6 			0.6 			1.7 			2.0 		
Allowance for Equity Funds Used During Construction		3.4 			1.6 			5.7 			4.5 		
Non-Service Cost Components of Net Periodic Benefit Cost		2.1 			2.1 			6.3 			6.4 		
	
Interest Expense		(29.3)			(29.2)			(89.1)			(89.4)		
									
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS		98.7 			109.8 			174.2 			145.3 		
									
Income Tax Expense (Benefit)		10.8 			(0.7)			12.5 			— 		
Equity Earnings of Unconsolidated Subsidiary		0.7 			0.8 			2.2 			2.3 		
									
NET INCOME		88.6 			111.3 			163.9 			147.6 		
									
Net Income Attributable to Noncontrolling Interest		0.7 			0.8 			2.1 			3.1 		
									
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER		$	87.9 			$	110.5 			$	161.8 			$	144.5 		
									
The common stock of SWEPCo is wholly-owned by Parent.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
128

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
 		2020		2019		2020		2019	
Net Income		$	88.6 			$	111.3 			$	163.9 			$	147.6 		
									
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES		 		 		 		 	
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2020 and 2019, Respectively		0.4 			0.3 			1.1 			1.1 		
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $0 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $(0.3) and $(0.2) for the Nine Months Ended September 30, 2020 and 2019, Respectively		(0.4)			(0.3)			(1.1)			(0.9)		
									
TOTAL OTHER COMPREHENSIVE INCOME		— 			— 			— 			0.2 		
									
TOTAL COMPREHENSIVE INCOME		88.6 			111.3 			163.9 			147.8 		
									
Total Comprehensive Income Attributable to Noncontrolling Interest		0.7 			0.8 			2.1 			3.1 		
									
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER		$	87.9 			$	110.5 			$	161.8 			$	144.7 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
129

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

	SWEPCo Common Shareholder		 		 	
	Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Noncontrolling
Interest		Total	
TOTAL EQUITY – DECEMBER 31, 2018	$	135.7 			$	676.6 			$	1,508.4 			$	(5.4)			$	0.3 			$	2,315.6 		
												
Common Stock Dividends					(18.7)							(18.7)		
Common Stock Dividends – Nonaffiliated									(1.1)			(1.1)		
	
Net Income					27.8 					1.2 			29.0 		
Other Comprehensive Income							0.1 					0.1 		
TOTAL EQUITY – MARCH 31, 2019	135.7 			676.6 			1,517.5 			(5.3)			0.4 			2,324.9 		
												
Common Stock Dividends					(18.8)							(18.8)		
Common Stock Dividends – Nonaffiliated	 		 		 		 		(1.1)			(1.1)		
Net Income	 		 		6.2 			 		1.1 			7.3 		
Other Comprehensive Income	 		 		 		0.1 			 		0.1 		
TOTAL EQUITY – JUNE 30, 2019	135.7 			676.6 			1,504.9 			(5.2)			0.4 			2,312.4 		

Common Stock Dividends – Nonaffiliated									(1.1)			(1.1)		
Net Income					110.5 					0.8 			111.3 		
	
TOTAL EQUITY – SEPTEMBER 30, 2019	$	135.7 			$	676.6 			$	1,615.4 			$	(5.2)			$	0.1 			$	2,422.6 		
												
TOTAL EQUITY – DECEMBER 31, 2019	$	135.7 			$	676.6 			$	1,629.5 			$	(1.3)			$	0.6 			$	2,441.1 		

Common Stock Dividends – Nonaffiliated									(0.7)			(0.7)		
ASU 2016-13 Adoption					1.6 							1.6 		
Net Income					15.1 					1.0 			16.1 		
	
TOTAL EQUITY – MARCH 31, 2020	135.7 			676.6 			1,646.2 			(1.3)			0.9 			2,458.1 		

Common Stock Dividends – Nonaffiliated	 		 		 		 		(1.2)			(1.2)		
Net Income	 		 		58.8 			 		0.4 			59.2 		
	
TOTAL EQUITY – JUNE 30, 2020	135.7 			676.6 			1,705.0 			(1.3)			0.1 			2,516.1 		
												
Reverse Common Stock Split (a)	(135.6)			135.6 									— 		
	
Common Stock Dividends – Nonaffiliated									(0.4)			(0.4)		
Net Income					87.9 					0.7 			88.6 		
	
TOTAL EQUITY – SEPTEMBER 30, 2020	$	0.1 			$	812.2 			$	1,792.9 			$	(1.3)			$	0.4 			$	2,604.3 		

		
(a)	See Note 12 - Financing Activities for additional information.	
		
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
130

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)

 		September 30,		December 31,	
 		2020		2019	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	25.6 			$	1.6 		
Advances to Affiliates		2.1 			2.1 		
Accounts Receivable:		 		 	
Customers		12.7 			29.0 		
Affiliated Companies		28.3 			34.5 		
Miscellaneous		24.4 			13.5 		
Allowance for Uncollectible Accounts		— 			(1.7)		
Total Accounts Receivable		65.4 			75.3 		
Fuel
(September 30, 2020 and December 31, 2019 Amounts Include $48.7 and $47, Respectively, Related to Sabine)		210.5 			140.1 		
Materials and Supplies
(September 30, 2020 and December 31, 2019 Amounts Include $24 and $23.1, Respectively, Related to Sabine)		99.2 			94.0 		
Risk Management Assets		4.5 			6.4 		

Regulatory Asset for Under-Recovered Fuel Costs		7.0 			4.9 		
Prepayments and Other Current Assets		29.7 			29.7 		
TOTAL CURRENT ASSETS		444.0 			354.1 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Generation		4,674.7 			4,691.4 		
Transmission		2,109.6 			2,056.5 		
Distribution		2,356.6 			2,270.7 		
Other Property, Plant and Equipment
(September 30, 2020 and December 31, 2019 Amounts Include $216.8 and $212.3, Respectively, Related to Sabine)		792.5 			733.4 		
Construction Work in Progress		272.3 			216.9 		
Total Property, Plant and Equipment		10,205.7 			9,968.9 		
Accumulated Depreciation and Amortization
(September 30, 2020 and December 31, 2019 Amounts Include $117.4 and $107.5, Respectively, Related to Sabine)		3,092.6 			2,873.7 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		7,113.1 			7,095.2 		
					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		334.8 			222.4 		

Deferred Charges and Other Noncurrent Assets		245.4 			160.5 		
TOTAL OTHER NONCURRENT ASSETS		580.2 			382.9 		
					
TOTAL ASSETS		$	8,137.3 			$	7,832.2 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
131

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2020 and December 31, 2019
(Unaudited)

 		September 30,		December 31,	
 		2020		2019	
 		(in millions)	
CURRENT LIABILITIES		 		 	
Advances from Affiliates		$	71.8 			$	59.9 		
Accounts Payable:		 		 	
General		183.3 			138.0 		
Affiliated Companies		80.5 			53.6 		
Short-term Debt – Nonaffiliated		42.0 			18.3 		
Long-term Debt Due Within One Year – Nonaffiliated		6.2 			121.2 		
Risk Management Liabilities		0.1 			1.9 		
Customer Deposits		63.7 			65.0 		
Accrued Taxes		90.1 			41.8 		
Accrued Interest		23.0 			34.6 		
	
Obligations Under Operating Leases		8.1 			6.5 		
Regulatory Liability for Over-Recovered Fuel Costs		32.0 			13.6 		
Other Current Liabilities		98.7 			120.3 		
TOTAL CURRENT LIABILITIES		699.5 			674.7 		
					
NONCURRENT LIABILITIES		 		 	
Long-term Debt – Nonaffiliated		2,631.1 			2,534.4 		
Long-term Risk Management Liabilities		0.7 			3.1 		
Deferred Income Taxes		965.0 			940.9 		
Regulatory Liabilities and Deferred Investment Tax Credits		877.5 			892.3 		
Asset Retirement Obligations		202.4 			196.7 		

Obligations Under Operating Leases		43.8 			34.7 		
Deferred Credits and Other Noncurrent Liabilities		113.0 			114.3 		
TOTAL NONCURRENT LIABILITIES		4,833.5 			4,716.4 		
					
TOTAL LIABILITIES		5,533.0 			5,391.1 		
					
Rate Matters (Note 4)					
Commitments and Contingencies (Note 5)					
					
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		1,792.9 			1,629.5 		
Accumulated Other Comprehensive Income (Loss)		(1.3)			(1.3)		
TOTAL COMMON SHAREHOLDER’S EQUITY		2,603.9 			2,440.5 		
					
Noncontrolling Interest		0.4 			0.6 		
					
TOTAL EQUITY		2,604.3 			2,441.1 		
					
TOTAL LIABILITIES AND EQUITY		$	8,137.3 			$	7,832.2 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
132

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)

 		Nine Months Ended September 30,	
 		2020		2019	
OPERATING ACTIVITIES		 		 	
Net Income		$	163.9 			$	147.6 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:		 		 	
Depreciation and Amortization		203.9 			187.1 		
Deferred Income Taxes		(0.3)			(15.9)		
	
Allowance for Equity Funds Used During Construction		(5.7)			(4.5)		
Mark-to-Market of Risk Management Contracts		(2.3)			(2.5)		
Pension Contributions to Qualified Plan Trust		(8.9)			— 		
Property Taxes		(16.5)			(16.1)		
Deferred Fuel Over/Under-Recovery, Net		16.3 			14.1 		
Change in Regulatory Assets		(64.5)			5.7 		
Change in Other Noncurrent Assets		3.2 			(2.2)		
Change in Other Noncurrent Liabilities		21.0 			5.8 		
Changes in Certain Components of Working Capital:		 		 	
Accounts Receivable, Net		8.0 			(17.2)		
Fuel, Materials and Supplies		(70.9)			(17.7)		
Accounts Payable		88.0 			(12.8)		
Accrued Taxes, Net		46.6 			54.1 		
	
Other Current Assets		1.3 			(4.5)		
Other Current Liabilities		(50.3)			(13.9)		
Net Cash Flows from Operating Activities		332.8 			307.1 		
					
INVESTING ACTIVITIES		 		 	
Construction Expenditures		(319.5)			(277.3)		
Change in Advances to Affiliates, Net		— 			74.9 		
Other Investing Activities		4.8 			(1.2)		
Net Cash Flows Used for Investing Activities		(314.7)			(203.6)		
					
FINANCING ACTIVITIES		 		 	

Change in Short-term Debt – Nonaffiliated		23.7 			— 		
Change in Advances from Affiliates, Net		11.9 			— 		
Retirement of Long-term Debt – Nonaffiliated		(19.7)			(58.2)		
Principal Payments for Finance Lease Obligations		(8.0)			(8.1)		
Dividends Paid on Common Stock		— 			(37.5)		
Dividends Paid on Common Stock – Nonaffiliated		(2.3)			(3.3)		
Other Financing Activities		0.3 			0.5 		
Net Cash Flows from (Used for) Financing Activities		5.9 			(106.6)		
					
Net Increase (Decrease) in Cash and Cash Equivalents		24.0 			(3.1)		
Cash and Cash Equivalents at Beginning of Period		1.6 			24.5 		
Cash and Cash Equivalents at End of Period		$	25.6 			$	21.4 		
					
SUPPLEMENTARY INFORMATION		 		 	
Cash Paid for Interest, Net of Capitalized Amounts		$	95.2 			$	95.1 		
Net Cash Paid for Income Taxes		11.9 			7.3 		
Noncash Acquisitions Under Finance Leases		5.9 			4.7 		
Construction Expenditures Included in Current Liabilities as of September 30,		50.6 			52.0 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.	
133

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS

The condensed notes to condensed financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise:

Note		Registrant		Page
Number	
					
Significant Accounting Matters		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		135	
New Accounting Standards		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		138	
Comprehensive Income		AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo		139	
Rate Matters		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		148	
Commitments, Guarantees and Contingencies		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		159	
Acquisitions and Impairments		AEP, APCo		164	
Benefit Plans		AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo		166	
Business Segments		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		171	
Derivatives and Hedging		AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo		176	
Fair Value Measurements		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		188	
Income Taxes		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		204	
Financing Activities		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		206	
	
Property, Plant and Equipment		AEP, APCo		214	
Revenue from Contracts with Customers		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		215	
134

1.  SIGNIFICANT ACCOUNTING MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC.  Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant.  Net income for the three and nine months ended September 30, 2020 is not necessarily indicative of results that may be expected for the year ending December 31, 2020.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2019 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2020.

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 could reduce future demand for energy, particularly from commercial and industrial customers.  The Registrants are taking steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. 

As of September 30, 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 three and nine months ended September 30, 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 within the AEPSC and was allocated among affiliated entities including the Registrant Subsidiaries. The impact of this program was immaterial on the Registrants’ financial statements as of September 30, 2020.

135

Earnings Per Share (EPS) (Applies to AEP)

Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted-average number of common shares outstanding during the period.  Diluted EPS is calculated by adjusting the weighted-average outstanding common shares, assuming conversion of all potentially dilutive stock awards.

The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:

	Three Months Ended September 30,	
	2020		2019	
	(in millions, except per share data)	
	 		$/share				$/share	

Earnings Attributable to AEP Common Shareholders	$	748.6 			 		$	733.5 			 	
								
Weighted Average Number of Basic Shares Outstanding	496.2 			$	1.51 			493.8 			$	1.49 		
Weighted Average Dilutive Effect of Stock-Based Awards	1.3 			(0.01)			1.7 			(0.01)		
Weighted Average Number of Diluted Shares Outstanding	497.5 			$	1.50 			495.5 			$	1.48 		

	Nine Months Ended September 30,	
	2020		2019	
	(in millions, except per share data)	
			$/share				$/share	

Earnings Attributable to AEP Common Shareholders	$	1,764.6 					$	1,767.6 				
								
Weighted Average Number of Basic Shares Outstanding	495.5 			$	3.56 			493.6 			$	3.58 		
Weighted Average Dilutive Effect of Stock-Based Awards	1.4 			(0.01)			1.5 			(0.01)		
Weighted Average Number of Diluted Shares Outstanding	496.9 			$	3.55 			495.1 			$	3.57 		

Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2020 and 2019, as the dilutive stock price thresholds were not met. See Note 12 - Financing Activities for more information related to Equity Units.

There were no antidilutive shares outstanding as of September 30, 2020 and 2019.

Restricted Cash (Applies to AEP, AEP Texas and APCo)

Restricted Cash primarily included funds held by trustee for the payment of securitization bonds and contractually restricted deposits held for the future payment of the remaining construction activities at Santa Rita East.

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statements of cash flows:

		September 30, 2020	
		AEP		AEP Texas		APCo	
		(in millions)	
Cash and Cash Equivalents		$	409.7 			$	0.1 			$	3.9 		
Restricted Cash		54.1 			44.8 			9.3 		
Total Cash, Cash Equivalents and Restricted Cash		$	463.8 			$	44.9 			$	13.2 		

																					
		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 		
136

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Allowance for Uncollectible Accounts

Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. The assessment is performed separately by each participating AEP subsidiary, which inherently contemplates any differences in geographical risk characteristics for the allowance. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified. In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for “Credit Losses.” Management’s assessments contemplate expected losses over the life of the accounts receivable.
137

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.

The new accounting guidance is effective for all entities as of March 12, 2020 through December 31, 2022. The amendments may be applied to contract modifications as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. The amendments may be applied to eligible hedging relationships existing as of the beginning of the interim period that includes March 12, 2020 and to new eligible hedging relationships entered into after the beginning of the interim period that includes March 12, 2020. The one-time election to sell, transfer, or both sell and transfer debt securities classified as held-to-maturity may be made at any time after March 12, 2020 but no later than December 31, 2022. Management has yet to apply the amendments in the new standard to any contract modifications, hedging relationships, or debt securities. Management is analyzing the impact of this new standard and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows.
138

3.  COMPREHENSIVE INCOME

The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional details.

AEP

 		Cash Flow Hedges		Pension		 	
Three Months Ended September 30, 2020		Commodity		Interest Rate		and OPEB		Total	
 		(in millions)	
Balance in AOCI as of June 30, 2020		$	(81.4)			$	(55.3)			$	(36.2)			$	(172.9)		
Change in Fair Value Recognized in AOCI		10.2 			1.9 		(a)	— 			12.1 		
Amount of (Gain) Loss Reclassified from AOCI									
Generation & Marketing Revenues (b)		(0.1)			— 			— 			(0.1)		
Purchased Electricity for Resale (b)		33.3 			— 			— 			33.3 		
Interest Expense (b)		— 			1.3 			— 			1.3 		
Amortization of Prior Service Cost (Credit)		— 			— 			(4.9)			(4.9)		
Amortization of Actuarial (Gains) Losses		— 			— 			2.6 			2.6 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		33.2 			1.3 			(2.3)			32.2 		
Income Tax (Expense) Benefit		7.1 			0.2 			(0.5)			6.8 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		26.1 			1.1 			(1.8)			25.4 		
Net Current Period Other Comprehensive Income (Loss)		36.3 			3.0 			(1.8)			37.5 		
Balance in AOCI as of September 30, 2020		$	(45.1)			$	(52.3)			$	(38.0)			$	(135.4)		

 		Cash Flow Hedges		Pension		 	
Three Months Ended September 30, 2019		Commodity		Interest Rate		and OPEB		Total	
 		(in millions)	
Balance in AOCI as of June 30, 2019		$	(127.2)			$	(15.9)			$	(87.6)			$	(230.7)		
Change in Fair Value Recognized in AOCI		38.4 			(0.8)		(c)	— 			37.6 		
Amount of (Gain) Loss Reclassified from AOCI									
Generation & Marketing Revenues (b)		(0.1)			— 			— 			(0.1)		
Purchased Electricity for Resale (b)		8.5 			— 			— 			8.5 		
	
Amortization of Prior Service Cost (Credit)		— 			— 			(4.8)			(4.8)		
Amortization of Actuarial (Gains) Losses		— 			— 			3.0 			3.0 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		8.4 			— 			(1.8)			6.6 		
Income Tax (Expense) Benefit		1.8 			— 			(0.4)			1.4 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		6.6 			— 			(1.4)			5.2 		
Net Current Period Other Comprehensive Income (Loss)		45.0 			(0.8)			(1.4)			42.8 		
Balance in AOCI as of September 30, 2019		$	(82.2)			$	(16.7)			$	(89.0)			$	(187.9)		

139

AEP

 		Cash Flow Hedges		Pension		 	
Nine Months Ended September 30, 2020		Commodity		Interest Rate		and OPEB		Total	
 		(in millions)	
Balance in AOCI as of December 31, 2019		$	(103.5)			$	(11.5)			$	(32.7)			$	(147.7)		
Change in Fair Value Recognized in AOCI		(48.6)			(43.6)		(a)	— 			(92.2)		
Amount of (Gain) Loss Reclassified from AOCI									
Generation & Marketing Revenues (b)		(0.3)			— 			— 			(0.3)		
Purchased Electricity for Resale (b)		135.7 			— 			— 			135.7 		
Interest Expense (b)		— 			3.6 			— 			3.6 		
Amortization of Prior Service Cost (Credit)		— 			— 			(14.4)			(14.4)		
Amortization of Actuarial (Gains) Losses		— 			— 			7.7 			7.7 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		135.4 			3.6 			(6.7)			132.3 		
Income Tax (Expense) Benefit		28.4 			0.8 			(1.4)			27.8 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		107.0 			2.8 			(5.3)			104.5 		
Net Current Period Other Comprehensive Income (Loss)		58.4 			(40.8)			(5.3)			12.3 		
Balance in AOCI as of September 30, 2020		$	(45.1)			$	(52.3)			$	(38.0)			$	(135.4)		

 		Cash Flow Hedges		Pension		 	
Nine Months Ended September 30, 2019		Commodity		Interest Rate		and OPEB		Total	
 		(in millions)	
Balance in AOCI as of December 31, 2018		$	(23.0)			$	(12.6)			$	(84.8)			$	(120.4)		
Change in Fair Value Recognized in AOCI		(92.3)			(4.5)		(c)	— 			(96.8)		
Amount of (Gain) Loss Reclassified from AOCI									
Generation & Marketing Revenues (b)		(0.1)			— 			— 			(0.1)		
Purchased Electricity for Resale (b)		42.0 			— 			— 			42.0 		
Interest Expense (b)		— 			0.5 			— 			0.5 		
Amortization of Prior Service Cost (Credit)		— 			— 			(14.3)			(14.3)		
Amortization of Actuarial (Gains) Losses		— 			— 			9.0 			9.0 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		41.9 			0.5 			(5.3)			37.1 		
Income Tax (Expense) Benefit		8.8 			0.1 			(1.1)			7.8 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		33.1 			0.4 			(4.2)			29.3 		
Net Current Period Other Comprehensive Income (Loss)		(59.2)			(4.1)			(4.2)			(67.5)		
Balance in AOCI as of September 30, 2019		$	(82.2)			$	(16.7)			$	(89.0)			$	(187.9)		

140

AEP Texas

		Cash Flow Hedge –		Pension			
Three Months Ended September 30, 2020		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of June 30, 2020		$	(2.9)			$	(9.3)			$	(12.2)		
Change in Fair Value Recognized in AOCI		— 			— 			— 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		0.4 			— 			0.4 		
Amortization of Prior Service Cost (Credit)		— 			(0.1)			(0.1)		
Amortization of Actuarial (Gains) Losses		— 			0.1 			0.1 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.4 			— 			0.4 		
Income Tax (Expense) Benefit		0.1 			— 			0.1 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.3 			— 			0.3 		
Net Current Period Other Comprehensive Income (Loss)		0.3 			— 			0.3 		
Balance in AOCI as of September 30, 2020		$	(2.6)			$	(9.3)			$	(11.9)		

		Cash Flow Hedge –		Pension			
Three Months Ended September 30, 2019		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of June 30, 2019		$	(3.9)			$	(10.6)			$	(14.5)		
Change in Fair Value Recognized in AOCI		0.3 			— 			0.3 		
Amount of (Gain) Loss Reclassified from AOCI							

	
Amortization of Prior Service Cost (Credit)		— 			(0.1)			(0.1)		
Amortization of Actuarial (Gains) Losses		— 			0.1 			0.1 		
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)		0.3 			— 			0.3 		
Balance in AOCI as of September 30, 2019		$	(3.6)			$	(10.6)			$	(14.2)		

		Cash Flow Hedge –		Pension			
Nine Months Ended September 30, 2020		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of December 31, 2019		$	(3.4)			$	(9.4)			$	(12.8)		
Change in Fair Value Recognized in AOCI		— 			— 			— 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		1.0 			— 			1.0 		
Amortization of Prior Service Cost (Credit)		— 			(0.1)			(0.1)		
Amortization of Actuarial (Gains) Losses		— 			0.2 			0.2 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.0 			0.1 			1.1 		
Income Tax (Expense) Benefit		0.2 			— 			0.2 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.8 			0.1 			0.9 		
Net Current Period Other Comprehensive Income (Loss)		0.8 			0.1 			0.9 		
Balance in AOCI as of September 30, 2020		$	(2.6)			$	(9.3)			$	(11.9)		

		Cash Flow Hedge –		Pension			
Nine Months Ended September 30, 2019		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of December 31, 2018		$	(4.4)			$	(10.7)			$	(15.1)		
Change in Fair Value Recognized in AOCI		0.3 			— 			0.3 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		0.6 			— 			0.6 		
Amortization of Prior Service Cost (Credit)		— 			(0.1)			(0.1)		
Amortization of Actuarial (Gains) Losses		— 			0.2 			0.2 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.6 			0.1 			0.7 		
Income Tax (Expense) Benefit		0.1 			— 			0.1 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.5 			0.1 			0.6 		
Net Current Period Other Comprehensive Income (Loss)		0.8 			0.1 			0.9 		
Balance in AOCI as of September 30, 2019		$	(3.6)			$	(10.6)			$	(14.2)		

141

APCo

		Cash Flow Hedge –		Pension			
Three Months Ended September 30, 2020		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of June 30, 2020		$	(4.1)			$	2.2 			$	(1.9)		
Change in Fair Value Recognized in AOCI		0.7 			— 			0.7 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		(0.2)			— 			(0.2)		
Amortization of Prior Service Cost (Credit)		— 			(1.3)			(1.3)		
Amortization of Actuarial (Gains) Losses		— 			0.1 			0.1 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.2)			(1.2)			(1.4)		
Income Tax (Expense) Benefit		(0.1)			(0.3)			(0.4)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.1)			(0.9)			(1.0)		
Net Current Period Other Comprehensive Income (Loss)		0.6 			(0.9)			(0.3)		
Balance in AOCI as of September 30, 2020		$	(3.5)			$	1.3 			$	(2.2)		

		Cash Flow Hedge –		Pension			
Three Months Ended September 30, 2019		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of June 30, 2019		$	1.4 			$	(8.1)			$	(6.7)		
Change in Fair Value Recognized in AOCI		(0.3)			— 			(0.3)		
Amount of (Gain) Loss Reclassified from AOCI							

	
Amortization of Prior Service Cost (Credit)		— 			(1.4)			(1.4)		
Amortization of Actuarial (Gains) Losses		— 			0.6 			0.6 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		— 			(0.8)			(0.8)		
Income Tax (Expense) Benefit		— 			(0.2)			(0.2)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		— 			(0.6)			(0.6)		
Net Current Period Other Comprehensive Income (Loss)		(0.3)			(0.6)			(0.9)		
Balance in AOCI as of September 30, 2019		$	1.1 			$	(8.7)			$	(7.6)		

		Cash Flow Hedge –		Pension			
Nine Months Ended September 30, 2020		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of December 31, 2019		$	0.9 			$	4.1 			$	5.0 		
Change in Fair Value Recognized in AOCI		(3.8)			— 			(3.8)		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		(0.8)			— 			(0.8)		
Amortization of Prior Service Cost (Credit)		— 			(4.0)			(4.0)		
Amortization of Actuarial (Gains) Losses		— 			0.4 			0.4 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.8)			(3.6)			(4.4)		
Income Tax (Expense) Benefit		(0.2)			(0.8)			(1.0)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.6)			(2.8)			(3.4)		
Net Current Period Other Comprehensive Income (Loss)		(4.4)			(2.8)			(7.2)		
Balance in AOCI as of September 30, 2020		$	(3.5)			$	1.3 			$	(2.2)		

		Cash Flow Hedge –		Pension			
Nine Months Ended September 30, 2019		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of December 31, 2018		$	1.8 			$	(6.8)			$	(5.0)		
Change in Fair Value Recognized in AOCI		(0.3)			— 			(0.3)		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		(0.5)			— 			(0.5)		
Amortization of Prior Service Cost (Credit)		— 			(4.0)			(4.0)		
Amortization of Actuarial (Gains) Losses		— 			1.6 			1.6 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.5)			(2.4)			(2.9)		
Income Tax (Expense) Benefit		(0.1)			(0.5)			(0.6)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.4)			(1.9)			(2.3)		
Net Current Period Other Comprehensive Income (Loss)		(0.7)			(1.9)			(2.6)		
Balance in AOCI as of September 30, 2019		$	1.1 			$	(8.7)			$	(7.6)		

142

I&M

		Cash Flow Hedge –		Pension			
Three Months Ended September 30, 2020		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of June 30, 2020		$	(9.1)			$	(1.7)			$	(10.8)		
Change in Fair Value Recognized in AOCI		— 			— 			— 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		0.5 			— 			0.5 		
Amortization of Prior Service Cost (Credit)		— 			(0.3)			(0.3)		
Amortization of Actuarial (Gains) Losses		— 			0.2 			0.2 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.5 			(0.1)			0.4 		
Income Tax (Expense) Benefit		0.1 			— 			0.1 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.4 			(0.1)			0.3 		
Net Current Period Other Comprehensive Income (Loss)		0.4 			(0.1)			0.3 		
Balance in AOCI as of September 30, 2020		$	(8.7)			$	(1.8)			$	(10.5)		

		Cash Flow Hedge –		Pension			
Three Months Ended September 30, 2019		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of June 30, 2019		$	(10.7)			$	(2.4)			$	(13.1)		
Change in Fair Value Recognized in AOCI		0.4 			— 			0.4 		
Amount of (Gain) Loss Reclassified from AOCI							

	
Amortization of Prior Service Cost (Credit)		— 			(0.2)			(0.2)		
Amortization of Actuarial (Gains) Losses		— 			0.2 			0.2 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		— 			— 			— 		
Income Tax (Expense) Benefit		— 			— 			— 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		— 			— 			— 		
Net Current Period Other Comprehensive Income (Loss)		0.4 			— 			0.4 		
Balance in AOCI as of September 30, 2019		$	(10.3)			$	(2.4)			$	(12.7)		

		Cash Flow Hedge –		Pension			
Nine Months Ended September 30, 2020		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of December 31, 2019		$	(9.9)			$	(1.7)			$	(11.6)		
Change in Fair Value Recognized in AOCI		— 			— 			— 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		1.5 			— 			1.5 		
Amortization of Prior Service Cost (Credit)		— 			(0.6)			(0.6)		
Amortization of Actuarial (Gains) Losses		— 			0.5 			0.5 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.5 			(0.1)			1.4 		
Income Tax (Expense) Benefit		0.3 			— 			0.3 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.2 			(0.1)			1.1 		
Net Current Period Other Comprehensive Income (Loss)		1.2 			(0.1)			1.1 		
Balance in AOCI as of September 30, 2020		$	(8.7)			$	(1.8)			$	(10.5)		

		Cash Flow Hedge –		Pension			
Nine Months Ended September 30, 2019		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of December 31, 2018		$	(11.5)			$	(2.3)			$	(13.8)		
Change in Fair Value Recognized in AOCI		0.4 			— 			0.4 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		1.0 			— 			1.0 		
Amortization of Prior Service Cost (Credit)		— 			(0.6)			(0.6)		
Amortization of Actuarial (Gains) Losses		— 			0.5 			0.5 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.0 			(0.1)			0.9 		
Income Tax (Expense) Benefit		0.2 			— 			0.2 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.8 			(0.1)			0.7 		
Net Current Period Other Comprehensive Income (Loss)		1.2 			(0.1)			1.1 		
Balance in AOCI as of September 30, 2019		$	(10.3)			$	(2.4)			$	(12.7)		

143

OPCo

		Cash Flow Hedge –	
Three Months Ended September 30, 2020		Interest Rate	
 	(in millions)	
Balance in AOCI as of June 30, 2020		$	— 		
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 September 30, 2020		$	— 		

		Cash Flow Hedge –	
Three Months Ended September 30, 2019		Interest Rate	
 	(in millions)	
Balance in AOCI as of June 30, 2019		$	0.3 		
Change in Fair Value Recognized in AOCI		(0.2)		
Amount of (Gain) Loss Reclassified from AOCI			

Interest Expense (b)		(0.1)		

Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.1)		
Income Tax (Expense) Benefit		— 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.1)		
Net Current Period Other Comprehensive Income (Loss)		(0.3)		
Balance in AOCI as of September 30, 2019		$	— 		

		Cash Flow Hedge –	
Nine Months Ended September 30, 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 September 30, 2020		$	— 		

		Cash Flow Hedge –	
Nine Months Ended September 30, 2019		Interest Rate	
 	(in millions)	
Balance in AOCI as of December 31, 2018		$	1.0 		
Change in Fair Value Recognized in AOCI		(0.2)		
Amount of (Gain) Loss Reclassified from AOCI			

Interest Expense (b)		(1.0)		

Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.0)		
Income Tax (Expense) Benefit		(0.2)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.8)		
Net Current Period Other Comprehensive Income (Loss)		(1.0)		
Balance in AOCI as of September 30, 2019		$	— 		
144

PSO

		Cash Flow Hedge –	
Three Months Ended September 30, 2020		Interest Rate	
 	(in millions)	
Balance in AOCI as of June 30, 2020		$	0.6 		
Change in Fair Value Recognized in AOCI		— 		
Amount of (Gain) Loss Reclassified from AOCI			

Interest Expense (b)		(0.3)		

Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.3)		
Income Tax (Expense) Benefit		— 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.3)		
Net Current Period Other Comprehensive Income (Loss)		(0.3)		
Balance in AOCI as of September 30, 2020		$	0.3 		

		Cash Flow Hedge –	
Three Months Ended September 30, 2019		Interest Rate	
 	(in millions)	
Balance in AOCI as of June 30, 2019		$	1.6 		
Change in Fair Value Recognized in AOCI		(0.3)		
Amount of (Gain) Loss Reclassified from AOCI			

Interest Expense (b)		0.2 		

Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.2 		
Income Tax (Expense) Benefit		0.1 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.1 		
Net Current Period Other Comprehensive Income (Loss)		(0.2)		
Balance in AOCI as of September 30, 2019		$	1.4 		

		Cash Flow Hedge –	
Nine Months Ended September 30, 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)		(1.0)		

Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.0)		
Income Tax (Expense) Benefit		(0.2)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.8)		
Net Current Period Other Comprehensive Income (Loss)		(0.8)		
Balance in AOCI as of September 30, 2020		$	0.3 		

		Cash Flow Hedge –	
Nine Months Ended September 30, 2019		Interest Rate	
 	(in millions)	
Balance in AOCI as of December 31, 2018		$	2.1 		
Change in Fair Value Recognized in AOCI		(0.3)		
Amount of (Gain) Loss Reclassified from AOCI			

Interest Expense (b)		(0.5)		

Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.5)		
Income Tax (Expense) Benefit		(0.1)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.4)		
Net Current Period Other Comprehensive Income (Loss)		(0.7)		
Balance in AOCI as of September 30, 2019		$	1.4 		

145

SWEPCo

		Cash Flow Hedge –		Pension			
Three Months Ended September 30, 2020		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of June 30, 2020		$	(1.1)			$	(0.2)			$	(1.3)		
Change in Fair Value Recognized in AOCI		— 			— 			— 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		0.5 			— 			0.5 		
Amortization of Prior Service Cost (Credit)		— 			(0.5)			(0.5)		
Amortization of Actuarial (Gains) Losses		— 			— 			— 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.5 			(0.5)			— 		
Income Tax (Expense) Benefit		0.1 			(0.1)			— 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.4 			(0.4)			— 		
Net Current Period Other Comprehensive Income (Loss)		0.4 			(0.4)			— 		
Balance in AOCI as of September 30, 2020		$	(0.7)			$	(0.6)			$	(1.3)		

		Cash Flow Hedge –		Pension			
Three Months Ended September 30, 2019		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of June 30, 2019		$	(2.5)			$	(2.7)			$	(5.2)		
Change in Fair Value Recognized in AOCI		0.3 			— 			0.3 		
Amount of (Gain) Loss Reclassified from AOCI							

	
Amortization of Prior Service Cost (Credit)		— 			(0.5)			(0.5)		
Amortization of Actuarial (Gains) Losses		— 			0.2 			0.2 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		— 			(0.3)			(0.3)		
Income Tax (Expense) Benefit		— 			— 			— 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		— 			(0.3)			(0.3)		
Net Current Period Other Comprehensive Income (Loss)		0.3 			(0.3)			— 		
Balance in AOCI as of September 30, 2019		$	(2.2)			$	(3.0)			$	(5.2)		
146

SWEPCo

		Cash Flow Hedge –		Pension			
Nine Months Ended September 30, 2020		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of December 31, 2019		$	(1.8)			$	0.5 			$	(1.3)		
Change in Fair Value Recognized in AOCI		— 			— 			— 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		1.4 			— 			1.4 		
Amortization of Prior Service Cost (Credit)		— 			(1.5)			(1.5)		
Amortization of Actuarial (Gains) Losses		— 			0.1 			0.1 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.4 			(1.4)			— 		
Income Tax (Expense) Benefit		0.3 			(0.3)			— 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.1 			(1.1)			— 		
Net Current Period Other Comprehensive Income (Loss)		1.1 			(1.1)			— 		
Balance in AOCI as of September 30, 2020		$	(0.7)			$	(0.6)			$	(1.3)		

		Cash Flow Hedge –		Pension			
Nine Months Ended September 30, 2019		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of December 31, 2018		$	(3.3)			$	(2.1)			$	(5.4)		
Change in Fair Value Recognized in AOCI		0.3 			— 			0.3 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		1.0 			— 			1.0 		
Amortization of Prior Service Cost (Credit)		— 			(1.5)			(1.5)		
Amortization of Actuarial (Gains) Losses		— 			0.4 			0.4 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.0 			(1.1)			(0.1)		
Income Tax (Expense) Benefit		0.2 			(0.2)			— 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.8 			(0.9)			(0.1)		
Net Current Period Other Comprehensive Income (Loss)		1.1 			(0.9)			0.2 		
Balance in AOCI as of September 30, 2019		$	(2.2)			$	(3.0)			$	(5.2)		

(a)The change in fair value includes $(1) million and $6 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC for the three and nine months ended September 30, 2020, respectively.
(b)Amounts reclassified to the referenced line item on the statements of income.
(c)The change in fair value includes $2 million and $6 million related to AEP’s investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC for the three and nine months ended September 30, 2019, respectively.
147

4.  RATE MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

As discussed in the 2019 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2019 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2020 and updates the 2019 Annual Report.

Regulated Generating Units to be Retired (Applies to AEP, PSO and SWEPCo)

In September 2018, management announced that the Oklaunion Power Station was probable of abandonment and was expected to be retired. The Oklaunion Power Station was retired in September 2020.  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 non-affiliated third-party. See “Oklaunion Power Station” section of Note 6 for additional information.

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. In March 2020, management announced plans to retire the plant in 2021.

The table below summarizes the plant investment and their cost of removal, currently being recovered, as well as the regulatory assets for accelerated depreciation for the generating units as of September 30, 2020.

Plant		Gross
Investment
Including
CWIP		Accumulated
Depreciation		Net
Investment		Accelerated Depreciation Regulatory Asset			Materials and Supplies		Cost of
Removal
Regulatory
Liability		Expected
Retirement
Date		Remaining
Recovery
Period	
		(dollars in millions)	
Oklaunion Power Station		$	— 			$	— 			$	— 			$	38.0 		(a)		$	3.4 			$	5.2 			2020		27 years	
Dolet Hills Power Station		346.7 			250.0 			$	96.7 			50.4 		(b)		5.8 			24.0 			2021		27 years	

(a)In October 2018, PSO changed depreciation rates to utilize the 2020 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously OCC-approved depreciation rates for Oklaunion Power Station.
(b)In January 2020, SWEPCo changed depreciation rates to utilize the 2026 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously APSC-approved depreciation rates for Dolet Hills Power Station. In March 2020, SWEPCo changed depreciation rates again to utilize the accelerated 2021 end-of-life.

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 $153 million, including CWIP and materials and supplies, before cost of removal.
148

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the Lignite Mining Agreement, DHLC bills SWEPCo its proportionate share of incurred lignite extraction and associated mining-related costs as fuel is delivered. As of September 30, 2020, DHLC has unbilled lignite inventory and fixed costs of $36 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. In 2009, SWEPCo acquired interests in Oxbow, which owns mineral rights and leases land. Under a Joint Operating Agreement pertaining to the Oxbow mineral rights and land leases, Oxbow bills SWEPCo its proportionate share of incurred costs. As of September 30, 2020, Oxbow has unbilled fixed costs of $10 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. DHLC and Oxbow have billed SWEPCo $111 million for lignite deliveries from April 2020 through September 2020, which primarily includes accelerated depreciation and amortization of fixed costs. 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.

Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)

		AEP	
		September 30,		December 31,	
		2020		2019	
 Noncurrent Regulatory Assets		(in millions)	
		 		 	
Regulatory Assets Currently Earning a Return		 		 	
Dolet Hills Power Station Accelerated Depreciation		$	50.4 			$	— 		
Kentucky Deferred Purchase Power Expenses		38.5 			30.2 		
Oklaunion Power Station Accelerated Depreciation		38.0 			27.4 		
Plant Retirement Costs – Unrecovered Plant		35.2 			35.2 		
	
COVID-19		2.0 			— 		
Other Regulatory Assets Pending Final Regulatory Approval		2.2 			0.7 		
Regulatory Assets Currently Not Earning a Return		 		 	
Storm-Related Costs		86.3 			7.2 		
Plant Retirement Costs – Asset Retirement Obligation Costs		25.9 			30.1 		
COVID-19		20.3 			— 		
Asset Retirement Obligation		8.7 			7.2 		
Vegetation Management Program (a)		3.8 			29.4 		
Cook Plant Study Costs (b)		— 			7.6 		
Other Regulatory Assets Pending Final Regulatory Approval		5.3 			6.7 		
Total Regulatory Assets Pending Final Regulatory Approval (c)	$	316.6 			$	181.7 		

(a)In April 2020, $26 million of deferred expenses were approved for recovery. See “2019 Texas Base Rate Case” section below for additional information.
(b)Approved for recovery in the first quarter of 2020 in the Indiana Base Rate Case.
(c)APCo is currently in the process of retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of September 30, 2020 and December 31, 2019, APCo has approximately $52 million and $51 million, respectively, of Virginia jurisdictional AMR meters recorded in Total Property, Plant and Equipment - Net on its balance sheets. APCo is pursuing full recovery of these assets through its Virginia depreciation rates. See “2017-2019 Virginia Triennial Review” section below for additional information.
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		AEP Texas	
		September 30,		December 31,	
		2020		2019	
Noncurrent Regulatory Assets		(in millions)	
					
Regulatory Assets Currently Not Earning a Return		 		 	
COVID-19		$	10.9 			$	— 		
Vegetation Management Program (a)		3.8 			29.4 		
Other Regulatory Assets Pending Final Regulatory Approval		1.4 			1.4 		
Total Regulatory Assets Pending Final Regulatory Approval		$	16.1 			$	30.8 		

(a)In April 2020, $26 million of deferred expenses were approved for recovery. See “2019 Texas Base Rate Case” section below for additional information.

		APCo	
		September 30,		December 31,	
		2020		2019	
Noncurrent Regulatory Assets		(in millions)	
					
Regulatory Assets Currently Earning a Return					
COVID-19 – Virginia		$	2.0 			$	— 		
Plant Retirement Costs – Materials and Supplies		— 			0.5 		
Regulatory Assets Currently Not Earning a Return		 		 	
Plant Retirement Costs – Asset Retirement Obligation Costs		25.9 			30.1 		
COVID-19 – West Virginia		0.8 			— 		
	
Total Regulatory Assets Pending Final Regulatory Approval (a)		$	28.7 			$	30.6 		

(a)APCo is currently in the process of retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of September 30, 2020 and December 31, 2019, APCo has approximately $52 million and $51 million, respectively, of Virginia jurisdictional AMR meters recorded in Total Property, Plant and Equipment - Net on its balance sheets. APCo is pursuing full recovery of these assets through its Virginia depreciation rates. See “2017-2019 Virginia Triennial Review” section below for additional information.

 		I&M	
		September 30,		December 31,	
		2020		2019	
Noncurrent Regulatory Assets		(in millions)	
		 		 	
Regulatory Assets Currently Not Earning a Return		 		 	
COVID-19		$	3.1 			$	— 		
Cook Plant Study Costs (a)		— 			7.6 		
Other Regulatory Assets Pending Final Regulatory Approval		— 			0.1 		
Total Regulatory Assets Pending Final Regulatory Approval		$	3.1 			$	7.7 		

(a)Approved for recovery in the first quarter of 2020 in the Indiana Base Rate Case.
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 		OPCo	
		September 30,		December 31,	
		2020		2019	
Noncurrent Regulatory Assets		(in millions)	
		 		 	
Regulatory Assets Currently Not Earning a Return		 		 	

	
Storm-Related Costs		$	3.6 			$	— 		
COVID-19		2.9 			— 		
Other Regulatory Assets Pending Final Regulatory Approval		0.1 			0.1 		
Total Regulatory Assets Pending Final Regulatory Approval		$	6.6 			$	0.1 		

															
 		PSO	
		September 30,		December 31,	
		2020		2019	
Noncurrent Regulatory Assets		(in millions)	
		 		 	
Regulatory Assets Currently Earning a Return		 		 	
Oklaunion Power Station Accelerated Depreciation		$	38.0 			$	27.4 		
	
Regulatory Assets Currently Not Earning a Return		 		 	

Storm-Related Costs		9.4 			7.2 		
COVID-19		0.3 			— 		
Total Regulatory Assets Pending Final Regulatory Approval		$	47.7 			$	34.6 		

															
		SWEPCo	
		September 30,		December 31,	
		2020		2019	
Noncurrent Regulatory Assets		(in millions)	
		 		 	
Regulatory Assets Currently Earning a Return		 		 	
Dolet Hills Power Station Accelerated Depreciation		$	50.4 			$	— 		
Plant Retirement Costs – Unrecovered Plant, Louisiana		35.2 			35.2 		
Other Regulatory Assets Pending Final Regulatory Approval		2.2 			0.2 		
Regulatory Assets Currently Not Earning a Return		 		 	
Storm-Related Costs - Louisiana		67.3 			— 		
Asset Retirement Obligation - Louisiana		8.5 			7.2 		

COVID-19		1.7 			— 		
Other Regulatory Assets Pending Final Regulatory Approval		2.0 			3.7 		
Total Regulatory Assets Pending Final Regulatory Approval		$	167.3 			$	46.3 		

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

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 quarter of 2020, certain state regulators began to lift restrictions on disconnects. As of September 30, 2020, AEP resumed disconnections in its regulated jurisdictions with the exception of Virginia, West Virginia, Kentucky, Arkansas, Louisiana and Tennessee. AEP’s electric operating companies continue to work with regulators and stakeholders in these states and management currently anticipates resuming customary disconnection practices in the fourth quarter of 2020. 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
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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 initial COVID-19 orders with the exception of 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 of that the final order was issued. The order also states future financially based capital incentives will not be included in interim transmission and distribution rates and contains various ring-fencing provisions. As a result of the final order, AEP Texas will refund $275 million of Excess ADIT associated with certain depreciable property using ARAM to transmission customers. AEP Texas will determine how to refund the remaining Excess ADIT that is not subject to normalization requirements in future proceedings.

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

AEP Texas Interim Transmission and Distribution Rates

Through September 30, 2020, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is estimated to be $38 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.

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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 deems these costs to be substantially recovered by APCo during the triennial review period.

In March 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $65 million annual increase in base rates based upon a proposed 9.9% ROE. The requested annual increase includes $19 million related to depreciation for updated test year end depreciable balances and a proposed increase in APCo’s Virginia depreciation rates and $8 million related to APCo’s calculated shortfall in 2017-2019 APCo’s Virginia earnings. Inclusive of the 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 September 30, 2020 and December 31, 2019, APCo has approximately $52 million and $51 million of Virginia jurisdictional AMR meters as well as $82 million and $75 million of Virginia jurisdictional AMI meters recorded in Total Property, Plant and Equipment - Net on its balance sheets. APCo is pursuing full recovery of these assets through its Virginia depreciation rates as discussed above.

In July 2020, a certain intervenor filed testimony asserting that APCo had a revenue surplus of $23 million for its filed rate year based upon the intervenor’s recommended ROE of 8.75%. The intervenor also filed proposed adjustments to APCo’s requested revenue requirement including: (a) a reduction to depreciation expense to reflect a 2040 retirement date for Amos Plant instead of 2032 for Amos Units 1 and 2 and 2033 for Amos Unit 3 as proposed by APCo, (b) removal of AMI meters from rate base along with related depreciation and (c) a reduction of purchased power expense related to OVEC demand charges. This intervenor, along with one other intervenor, also proposed the removal of major storm expenses.

In addition, this certain intervenor submitted corrected testimony contending APCo’s earned return for the triennial period was 11.12%, which equates to a potential refund to customers of $34 million. The intervenor also filed a separate legal memorandum opposing the inclusion of the 2019 expensing of the retired coal-fired generation assets from APCo’s 2017-2019 earnings test results. The testimony also removed the related rate base associated with the retired coal units. Another intervenor recommended that APCo not earn a return on $114 million of prepaid pension and OPEB assets.

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In August and September 2020, the Virginia staff filed testimony supporting an annual APCo Virginia jurisdictional revenue deficiency of $17 million based upon an ROE of 8.73%. However, Virginia staff contends APCo’s earned return for the triennial period was 9.55%, which is above the 9.42% midpoint of APCo’s authorized ROE range. Based on Virginia law, a Virginia SCC order finding an earned ROE above the midpoint would prevent APCo from receiving a prospective increase in Virginia retail rates. In addition, the staff recommended that APCo: (a) reverse the pretax Virginia jurisdictional share of the $93 million expense recorded in December 2019 for its retired coal-fired generation assets and instead amortize the retired assets over a 10-year period beginning in 2015, (b) implement 2017 depreciation study rates, effective January 2018, which would increase depreciation expense by $18 million and $20 million in 2018 and 2019, respectively (including $5 million annually related to transmission), (c) implement 2019 depreciation study rates, effective January 2020, which would increase depreciation expense by $29 million annually (including $11 million related to transmission) starting January 1, 2020 and (d) remove $9 million of major storm expenses and $12 million of coal combustion by-product expenses from the requested annual increase in base rates.

APCo expects to receive an order in November 2020. If any APCo Virginia jurisdictional costs are not recoverable or if refunds of revenues collected from customers during the triennial review period are ordered by the Virginia SCC, 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.

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 September 30, 2020, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $1.1 billion. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring.

In 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for base rate proceedings. The rule requires ETT to file for a comprehensive base rate review no later than February 1, 2021.

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.

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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. A compliance filing will be made in January 2021 to adjust the final rate increase to reflect the lower of I&M’s actual or IURC-approved Indiana jurisdictional electric plant in service balance as of December 31, 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 will negatively impact I&M’s annual pretax earnings by approximately $20 million starting June 2020.

KPCo Rate Matters (Applies to AEP)

Kentucky Tax Reform

In May 2020, KPCo filed a request with the KPSC to issue a one-time refund of Excess ADIT that is not subject to normalization requirements to customers of approximately $11 million to eliminate certain customer delinquencies attributable to the COVID-19 pandemic. In October 2020, the KPSC denied KPCo’s request.

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 Unit Power Agreement expenses and related carrying charges over a 5-year period beginning in December 2022, through an existing purchased power rider.

In October 2020, various intervenors filed testimony recommending annual rate increases ranging from $0 to $17 million based upon a ROE ranging from 8.93% to 9.25%. Other differences between KPCo’s requested annual base rate increase and the intervenors’ recommendations are primarily due to: (a) a proposed change in the recovery period of Rockport Plant, Unit 2 SCR depreciation expense from three to ten years, (b) a proposal to remove certain employee-related expenses from the revenue requirement and (c) a recommendation that KPCo not earn a return on $64 million of prepaid pension and OPEB assets. In addition, intervenors expressed opposition to: (a) KPCo’s proposed recovery/return of certain annual PJM Open Access Transmission Tariff expenses below/above the corresponding level recovered in base rates through an existing rider, (b) deployment of AMI with cost recovery through a new rider and (c) KPCo’s proposed changes to its net metering tariff. KPCo will file rebuttal testimony in November 2020. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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. 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 Electric Security Plan 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 scheduled for December 2020.

As of September 30, 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
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collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition.

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 through a tax rider that will end when the Excess ADIT not subject to normalization requirements is fully refunded to customers which is currently estimated to be July 2020.

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. SWEPCo is currently evaluating recovery options for the storm damage in its Arkansas jurisdiction. As of September 30, 2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $69 million ($67 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $31 million ($30 million 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. Management currently estimates that SWEPCo has incurred incremental other operation and maintenance expenses ranging from $10 million to $18 million and incremental capital expenditures of up to $6 million. SWEPCo will seek deferral authority of incremental other operation and maintenance expenses from the LPSC. 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. 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.
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5.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are subject to certain claims and legal actions arising in the ordinary course of business.  In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted.  Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2019 Annual Report should be read in conjunction with this report.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.”  There is no collateral held in relation to any guarantees.  In the event any guarantee is drawn, there is no recourse to third-parties unless specified below.

Letters of Credit (Applies to AEP and AEP Texas)

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 September 30, 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 September 30, 2020 were as follows:

Company		Amount		Maturity	
 		(in millions)		 	
AEP		$	197.3 			October 2020 to August 2021	
AEP Texas		2.2 			July 2021	

Guarantees of Equity Method Investees (Applies to AEP)

In April 2019, AEP acquired Sempra Renewables LLC. See “Acquisitions” section of Note 6 for additional information.

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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 September 30, 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.

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 September 30, 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		$	49.8 		
AEP Texas		11.4 		
APCo		6.8 		
I&M		4.5 		
OPCo		7.9 		
PSO		4.6 		
SWEPCo		5.2 		

Rockport Lease (Applies to AEP and I&M)

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant).  The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.

The Owner Trustee owns the Plant and leases equal portions to AEGCo and I&M.  The lease is accounted for as an operating lease.  The lease term is for 33 years and at the end of the lease term, AEGCo and I&M have the option to renew the lease at a rate that approximates fair value.  The option to renew was not included in the measurement of the lease obligation as of September 30, 2020 as the execution of the option was not reasonably certain. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. 

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The future minimum lease payments for this sale-and-leaseback transaction as of September 30, 2020 were as follows:

Future Minimum Lease Payments		AEP (a)		I&M	
		(in millions)	
2020		$	73.9 			$	37.0 		
2021		147.8 			73.9 		
2022		147.5 			73.7 		
Total Future Minimum Lease Payments		$	369.2 			$	184.6 		

(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 September 30, 2020, the maximum potential amount of future payments required under the guaranteed leases was $50 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 September 30, 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.

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials.  The Registrants currently incur costs to dispose of these substances safely. For remediation processes not specifically discussed, management does not anticipate that the liabilities, if any, arising from such remediation processes would have a material effect on the financial statements.

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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 may begin recovering these costs through the E-RAC beginning July 1, 2022. APCo is permitted to record carrying costs on the unrecovered balance of closure costs at a weighted average cost of capital approved by the Virginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered from Virginia jurisdictional customers through the E-RAC.

NUCLEAR CONTINGENCIES (Applies to AEP and I&M)

I&M owns and operates the Cook Plant under licenses granted by the Nuclear Regulatory Commission.  I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

OPERATIONAL CONTINGENCIES

Rockport Plant Litigation (Applies to AEP and I&M)

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
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district court enter a judgment for the plaintiffs on their breach of contract claim. AEP’s memorandum in opposition was filed in October 2020. All deadlines, including discovery, are stayed, pending resolution of the motion.

Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management cannot determine a range of potential losses that is reasonably possible of occurring.

Patent Infringement Complaint (Applies to AEP, AEP Texas and SWEPCo)

In July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs) filed a patent infringement complaint against various parties, including AEP Texas, AGR, Cardinal Operating Company and SWEPCo (collectively, the AEP Defendants). The complaint 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.  In July 2020, plaintiffs amended the complaint to add three new patents. The amended complaint seeks injunctive relief and damages.  The case is scheduled for trial in January 2023. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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 are 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. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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6. ACQUISITIONS AND DISPOSITIONS

The disclosures in this note apply to AEP unless indicated otherwise.

ACQUISITIONS

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.

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.

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 September 30, 2020, the maximum potential amount of future payments associated with these guarantees was $166 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.

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.

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.
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DISPOSITIONS

Conesville Plant (Generation & Marketing Segment)

In June 2020, AEP and a non-affiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a non-affiliated 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 approximately $98 million, 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 in June 2020 and will make additional payments totaling $28 million in quarterly installments from October 2020 to April 2021 and payments totaling $44 million in quarterly installments from July 2021 to July 2022.

Oklaunion Power Station (Applies to AEP, AEP Texas and PSO)

In October 2020, AEP Texas, PSO and a non-affiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a non-affiliated 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 is expected to have an immaterial impact on the financial statements in the fourth quarter of 2020.

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7.  BENEFIT PLANS

The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.

AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans.  Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan.  AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees.

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans:

AEP

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	28.0 			$	23.8 			$	2.5 			$	2.4 		
Interest Cost	42.0 			51.1 			10.0 			12.6 		
Expected Return on Plan Assets	(66.3)			(74.0)			(23.9)			(23.4)		
Amortization of Prior Service Credit	— 			— 			(17.4)			(17.3)		
Amortization of Net Actuarial Loss	23.5 			14.4 			1.4 			5.5 		
Net Periodic Benefit Cost (Credit)	$	27.2 			$	15.3 			$	(27.4)			$	(20.2)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	84.0 			$	71.6 			$	7.5 			$	7.1 		
Interest Cost	125.9 			153.3 			29.9 			37.9 		
Expected Return on Plan Assets	(198.7)			(222.0)			(71.8)			(70.3)		
Amortization of Prior Service Credit	— 			— 			(52.3)			(51.8)		
Amortization of Net Actuarial Loss	70.3 			43.2 			4.4 			16.6 		
Net Periodic Benefit Cost (Credit)	$	81.5 			$	46.1 			$	(82.3)			$	(60.5)		

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AEP Texas

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	2.6 			$	2.2 			$	0.2 			$	0.1 		
Interest Cost	3.5 			4.4 			0.8 			1.0 		
Expected Return on Plan Assets	(5.7)			(6.5)			(2.0)			(1.9)		
Amortization of Prior Service Credit	— 			— 			(1.4)			(1.5)		
Amortization of Net Actuarial Loss	1.9 			1.2 			0.1 			0.5 		
Net Periodic Benefit Cost (Credit)	$	2.3 			$	1.3 			$	(2.3)			$	(1.8)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	7.6 			$	6.5 			$	0.6 			$	0.5 		
Interest Cost	10.5 			13.1 			2.4 			3.0 		
Expected Return on Plan Assets	(17.1)			(19.4)			(6.0)			(5.8)		
Amortization of Prior Service Credit	— 			— 			(4.4)			(4.4)		
Amortization of Net Actuarial Loss	5.8 			3.7 			0.4 			1.4 		
Net Periodic Benefit Cost (Credit)	$	6.8 			$	3.9 			$	(7.0)			$	(5.3)		

APCo

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	2.7 			$	2.4 			$	0.3 			$	0.2 		
Interest Cost	5.0 			6.3 			1.6 			2.2 		
Expected Return on Plan Assets	(8.4)			(9.4)			(3.6)			(3.7)		
Amortization of Prior Service Credit	— 			— 			(2.5)			(2.5)		
Amortization of Net Actuarial Loss	2.8 			1.8 			0.2 			1.0 		
Net Periodic Benefit Cost (Credit)	$	2.1 			$	1.1 			$	(4.0)			$	(2.8)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	7.9 			$	7.1 			$	0.8 			$	0.7 		
Interest Cost	15.2 			18.9 			4.9 			6.5 		
Expected Return on Plan Assets	(25.2)			(28.1)			(10.9)			(11.0)		
Amortization of Prior Service Credit	— 			— 			(7.6)			(7.5)		
Amortization of Net Actuarial Loss	8.4 			5.3 			0.7 			2.8 		
Net Periodic Benefit Cost (Credit)	$	6.3 			$	3.2 			$	(12.1)			$	(8.5)		
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I&M

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	3.9 			$	3.3 			$	0.4 			$	0.3 		
Interest Cost	4.9 			6.0 			1.2 			1.5 		
Expected Return on Plan Assets	(8.3)			(9.1)			(3.0)			(2.8)		
Amortization of Prior Service Credit	— 			— 			(2.3)			(2.4)		
Amortization of Net Actuarial Loss	2.7 			1.6 			0.1 			0.7 		
Net Periodic Benefit Cost (Credit)	$	3.2 			$	1.8 			$	(3.6)			$	(2.7)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	11.6 			$	10.0 			$	1.1 			$	1.0 		
Interest Cost	14.7 			17.9 			3.5 			4.4 		
Expected Return on Plan Assets	(24.9)			(27.5)			(8.8)			(8.5)		
Amortization of Prior Service Credit	— 			— 			(7.1)			(7.1)		
Amortization of Net Actuarial Loss	8.1 			4.9 			0.5 			2.0 		
Net Periodic Benefit Cost (Credit)	$	9.5 			$	5.3 			$	(10.8)			$	(8.2)		

OPCo

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	2.4 			$	1.9 			$	0.2 			$	0.2 		
Interest Cost	3.9 			4.8 			1.0 			1.4 		
Expected Return on Plan Assets	(6.6)			(7.3)			(2.6)			(2.7)		
Amortization of Prior Service Credit	— 			— 			(1.8)			(1.8)		
Amortization of Net Actuarial Loss	2.1 			1.3 			0.2 			0.6 		
Net Periodic Benefit Cost (Credit)	$	1.8 			$	0.7 			$	(3.0)			$	(2.3)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	7.2 			$	5.9 			$	0.7 			$	0.6 		
Interest Cost	11.6 			14.3 			3.1 			4.1 		
Expected Return on Plan Assets	(19.7)			(22.0)			(7.9)			(8.1)		
Amortization of Prior Service Credit	— 			— 			(5.3)			(5.2)		
Amortization of Net Actuarial Loss	6.4 			4.0 			0.5 			1.9 		
Net Periodic Benefit Cost (Credit)	$	5.5 			$	2.2 			$	(8.9)			$	(6.7)		

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PSO

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	1.9 			$	1.6 			$	0.1 			$	0.2 		
Interest Cost	2.1 			2.6 			0.6 			0.7 		
Expected Return on Plan Assets	(3.6)			(4.0)			(1.3)			(1.3)		
Amortization of Prior Service Credit	— 			— 			(1.0)			(1.1)		
Amortization of Net Actuarial Loss	1.1 			0.7 			— 			0.3 		
Net Periodic Benefit Cost (Credit)	$	1.5 			$	0.9 			$	(1.6)			$	(1.2)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	5.5 			$	4.9 			$	0.4 			$	0.5 		
Interest Cost	6.4 			7.9 			1.6 			2.0 		
Expected Return on Plan Assets	(10.9)			(12.2)			(3.9)			(3.9)		
Amortization of Prior Service Credit	— 			— 			(3.2)			(3.2)		
Amortization of Net Actuarial Loss	3.5 			2.2 			0.2 			0.9 		
Net Periodic Benefit Cost (Credit)	$	4.5 			$	2.8 			$	(4.9)			$	(3.7)		

SWEPCo

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	2.6 			$	2.1 			$	0.2 			$	0.2 		
Interest Cost	2.5 			3.1 			0.6 			0.7 		
Expected Return on Plan Assets	(3.9)			(4.4)			(1.5)			(1.5)		
Amortization of Prior Service Credit	— 			— 			(1.3)			(1.3)		
Amortization of Net Actuarial Loss	1.4 			0.9 			0.1 			0.4 		
Net Periodic Benefit Cost (Credit)	$	2.6 			$	1.7 			$	(1.9)			$	(1.5)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2020		2019		2020		2019	
 	(in millions)	
Service Cost	$	7.5 			$	6.4 			$	0.6 			$	0.6 		
Interest Cost	7.6 			9.3 			1.9 			2.3 		
Expected Return on Plan Assets	(11.7)			(13.3)			(4.7)			(4.5)		
Amortization of Prior Service Credit	— 			— 			(3.9)			(3.9)		
Amortization of Net Actuarial Loss	4.2 			2.6 			0.3 			1.1 		
Net Periodic Benefit Cost (Credit)	$	7.6 			$	5.0 			$	(5.8)			$	(4.4)		

169

Qualified Pension Contribution (Applies to all Registrants except AEPTCo and PSO)

For the qualified pension plan, discretionary contributions may be made to maintain the funded status of the plan. In the third quarter of 2020, AEP made a discretionary contribution to the qualified pension plan. The following table provides details of the contribution by Registrant:
									
Company		Qualified Pension Plan	
		(in millions)	
AEP		$	110.3 		
AEP Texas		11.3 		
APCo		7.0 		
I&M		6.4 		
OPCo		0.1 		
	
SWEPCo		8.9 		
170

8.  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 ROEs.
•Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ROEs.

Generation & Marketing

•Competitive generation in ERCOT and PJM.
•Contracted renewable energy investments and management services.
•Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO.

The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense, income tax expense and other nonallocated costs.
171

The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2020 and 2019 and reportable segment balance sheet information as of September 30, 2020 and December 31, 2019.

	Three Months Ended September 30, 2020	
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation
&
Marketing		Corporate and Other (a)		Reconciling Adjustments		Consolidated	
 	(in millions)	
Revenues from:	 		 		 		 		 				 	
External Customers	$	2,400.1 			$	1,124.1 			$	73.4 			$	464.8 			$	4.0 			$	— 			$	4,066.4 		
Other Operating Segments	34.7 			41.2 			244.5 			25.2 			28.6 			(374.2)			— 		
Total Revenues	$	2,434.8 			$	1,165.3 			$	317.9 			$	490.0 			$	32.6 			$	(374.2)			$	4,066.4 		

	
Net Income (Loss)	$	394.2 			$	147.4 			$	139.3 			$	114.6 			$	(47.3)			$	— 			$	748.2 		
														
	Three Months Ended September 30, 2019	
 	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation
&
Marketing		Corporate and Other (a)		Reconciling Adjustments		Consolidated	
 	(in millions)	
Revenues from:	 		 		 		 		 				 	
External Customers	$	2,598.9 			$	1,147.3 			$	65.5 			$	501.2 			$	2.1 			$	— 			$	4,315.0 		
Other Operating Segments	46.6 			39.3 			207.5 			32.5 			22.3 			(348.2)			— 		
Total Revenues	$	2,645.5 			$	1,186.6 			$	273.0 			$	533.7 			$	24.4 			$	(348.2)			$	4,315.0 		

	
Net Income (Loss)	$	438.4 			$	133.7 			$	127.0 			$	88.7 			$	(53.9)			$	— 			$	733.9 		

	

	

	

	

	

	

	

	

														
	Nine Months Ended September 30, 2020	
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation
&
Marketing		Corporate and Other (a)		Reconciling Adjustments		Consolidated	
	(in millions)	
Revenues from:														
External Customers	$	6,655.4 			$	3,208.7 			$	215.7 			$	1,223.4 			$	4.7 			$	— 			$	11,307.9 		
Other Operating Segments	98.1 			98.0 			662.1 			82.1 			67.3 			(1,007.6)			— 		
Total Revenues	$	6,753.5 			$	3,306.7 			$	877.8 			$	1,305.5 			$	72.0 			$	(1,007.6)			$	11,307.9 		

Net Income (Loss)	$	896.8 			$	403.1 			$	373.1 			$	203.6 			$	(114.6)			$	— 			$	1,762.0 		
														
	Nine Months Ended September 30, 2019	
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation
&
Marketing		Corporate and Other (a)		Reconciling Adjustments		Consolidated	
	(in millions)	
Revenues from:														
External Customers	$	7,087.6 			$	3,328.7 			$	196.5 			$	1,323.8 			$	8.8 			$	— 			$	11,945.4 		
Other Operating Segments	85.0 			125.6 			611.8 			104.4 			64.9 			(991.7)			— 		
Total Revenues	$	7,172.6 			$	3,454.3 			$	808.3 			$	1,428.2 			$	73.7 			$	(991.7)			$	11,945.4 		

	
Net Income (Loss)	$	920.8 			$	421.6 			$	407.6 			$	133.1 			$	(116.0)			$	— 			$	1,767.1 		

172

																																													
		September 30, 2020	
		Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation
&
Marketing		Corporate and Other (a)		Reconciling
Adjustments		Consolidated	
 		(in millions)	
Total Property, Plant and Equipment		$	48,533.5 			$	20,738.7 			$	11,377.1 			$	1,854.4 			$	399.3 			$	— 			$	82,903.0 		
Accumulated Depreciation and Amortization		15,340.1 			3,891.6 			553.1 			150.1 			181.7 			— 			20,116.6 		
Total Property Plant and Equipment - Net		$	33,193.4 			$	16,847.1 			$	10,824.0 			$	1,704.3 			$	217.6 			$	— 			$	62,786.4 		

Total Assets		$	42,110.4 			$	19,250.3 			$	12,035.8 			$	3,368.6 			$	5,718.9 		(b)	$	(3,794.7)		(c)	$	78,689.3 		
															
Long-term Debt Due Within One Year:															
	
Nonaffiliated		1,313.7 			87.8 			2.3 			— 			507.8 		(d)	— 			1,911.6 		
															
Long-term Debt:															
Affiliated		59.0 			— 			— 			— 			— 			(59.0)			— 		
Nonaffiliated		12,048.7 			7,196.7 			4,123.2 			— 			4,786.9 		(d)	— 			28,155.5 		
															
Total Long-term Debt		$	13,421.4 			$	7,284.5 			$	4,125.5 			$	— 			$	5,294.7 			$	(59.0)			$	30,067.1 		

															
		December 31, 2019	
		Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation
&
Marketing		Corporate and Other (a)		Reconciling
Adjustments		Consolidated	
 		(in millions)	
Total Property, Plant and Equipment		$	47,323.7 			$	19,773.3 			$	10,334.0 			$	1,650.8 			$	418.4 			$	(354.5)		(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 		
															
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 		(d)	— 			25,126.8 		
															
Total Long-term Debt		$	12,925.7 			$	6,640.3 			$	3,593.8 			$	— 			$	3,624.7 			$	(59.0)			$	26,725.5 		

(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 are inclusive of 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.

173

AEPTCo’s Reportable Segments

AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities. The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems.

AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. The State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities.

The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2020 and 2019 and reportable segment balance sheet information as of September 30, 2020 and December 31, 2019.

	Three Months Ended September 30, 2020	
	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo
Consolidated	
	(in millions)	
Revenues from:								
External Customers	$	62.9 			$	— 			$	— 			$	62.9 		
Sales to AEP Affiliates	241.2 			— 			— 			241.2 		
	
Total Revenues	$	304.1 			$	— 			$	— 			$	304.1 		
								
Interest Income	$	— 			$	38.4 			$	(38.2)		(a)	$	0.2 		
Interest Expense	32.7 			38.2 			(38.2)		(a)	32.7 		
Income Tax Expense	31.7 			— 			— 			31.7 		

Net Income	$	117.5 			$	0.1 		(b)	$	— 			$	117.6 		
								
	Three Months Ended September 30, 2019	
	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo
Consolidated	
	(in millions)	
Revenues from:								
External Customers	$	54.0 			$	— 			$	— 			$	54.0 		
Sales to AEP Affiliates	205.7 			— 			— 			205.7 		
	
Total Revenues	$	259.7 			$	— 			$	— 			$	259.7 		
								
Interest Income	$	0.4 			$	32.3 			$	(31.9)		(a)	$	0.8 		
Interest Expense	26.4 			31.9 			(31.9)		(a)	26.4 		
Income Tax Expense	30.0 			0.1 			— 			30.1 		

Net Income	$	107.3 			$	0.3 		(b)	$	— 			$	107.6 		
174

																								
	Nine Months Ended September 30, 2020	
	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo Consolidated	
	(in millions)	
Revenues from:								
External Customers	$	184.6 			$	— 			$	— 			$	184.6 		
Sales to AEP Affiliates	652.6		— 			— 			652.6 		
Other Revenues	0.6 			— 			— 			0.6 		
Total Revenues	$	837.8 			$	— 			$	— 			$	837.8 		
								
Interest Income	$	0.9 			$	111.3 			$	(109.9)		(a)	$	2.3 		
Interest Expense	95.1 			109.9 			(109.9)		(a)	95.1 		
Income Tax Expense	82.7 			0.1 			— 			82.8 		

Net Income	$	308.0 			$	1.1 		(b)	$	— 			$	309.1 		
								
	Nine Months Ended September 30, 2019	
	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo Consolidated	
	(in millions)	
Revenues from:								
External Customers	$	162.1 			$	— 			$	— 			$	162.1 		
Sales to AEP Affiliates	608.0		— 			— 			608.0 		
	
Total Revenues	$	770.1 			$	— 			$	— 			$	770.1 		
								
Interest Income	$	0.8 			$	89.7 			$	(88.4)		(a)	$	2.1 		
Interest Expense	69.5		88.4		(88.4)		(a)	69.5	
Income Tax Expense	90.5 			0.2 			— 			90.7 		

Net Income	$	347.1 			$	0.8 		(b)	$	— 			$	347.9 		

	

	

	

	

	

	

	

	

	

	

	
	
	September 30, 2020	
	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo
Consolidated	
	(in millions)	
Total Transmission Property	$	10,921.3 			$	— 			$	— 			$	10,921.3 		
Accumulated Depreciation and Amortization	531.8 			— 			— 			531.8 		
Total Transmission Property – Net	$	10,389.5 			$	— 			$	— 			$	10,389.5 		
								
Notes Receivable - Affiliated	$	— 			$	3,947.9 			$	(3,947.9)		(c)	$	— 		
								
Total Assets	$	10,641.8 			$	4,104.1 		(d)	$	(4,047.2)		(e)	$	10,698.7 		
								
Total Long-term Debt	$	3,990.0 			$	3,947.9 			$	(3,990.0)		(c)	$	3,947.9 		
								
	December 31, 2019	
	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo
Consolidated	
	(in millions)	
Total Transmission Property	$	9,893.2 			$	— 			$	— 			$	9,893.2 		
Accumulated Depreciation and Amortization	402.3 			— 			— 			402.3 		
Total Transmission Property – Net	$	9,490.9 			$	— 			$	— 			$	9,490.9 		
								
Notes Receivable - Affiliated	$	— 			$	3,427.3 			$	(3,427.3)		(c)	$	— 		
								
Total Assets	$	9,865.0 			$	3,519.1 		(d)	$	(3,493.3)		(e)	$	9,890.8 		
								
Total Long-term Debt	$	3,465.0 			$	3,427.3 			$	(3,465.0)		(c)	$	3,427.3 		

(a)Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
(b)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(c)Elimination of intercompany debt.
(d)Includes the elimination of AEPTCo Parent’s investments in State Transcos.
(e)Primarily relates to the elimination of Notes Receivable from the State Transcos.

175

9.  DERIVATIVES AND HEDGING

The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity.

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.

The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets.  These risks include commodity price risks which may be subject to capacity risk, interest rate risk and credit risk.  These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates.  Management utilizes derivative instruments to manage these risks.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.

176

The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts:

Notional Volume of Derivative Instruments
September 30, 2020

Primary Risk
Exposure		Unit of
Measure		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
				(in millions)	
Commodity:		 						 		 		 		 		 	
Power		MWhs		390.6 			— 			71.7 			28.9 			3.1 			19.8 			5.6 		
	
Natural Gas		MMBtus		33.3 			— 			— 			— 			— 			— 			8.8 		
Heating Oil and Gasoline		Gallons		8.3 			2.2 			1.3 			0.8 			1.7 			0.9 			1.1 		
Interest Rate		USD		$	129.8 			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		
																	
Interest Rate on Long-term Debt		USD		$	200.0 			$	— 			$	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.
177

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $0 and $5 million as of September 30, 2020 and December 31, 2019, respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $9 million and $39 million as of September 30, 2020 and December 31, 2019, respectively. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third-parties against short-term and long-term risk management liabilities were immaterial for the Registrant Subsidiaries as of September 30, 2020 and December 31, 2019.
178

The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets:

AEP

Fair Value of Derivative Instruments
September 30, 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		$	253.7 			$	24.5 			$	0.6 			$	278.8 			$	(163.6)			$	115.2 		
Long-term Risk Management Assets		283.3 			17.5 			— 			300.8 			(57.9)			242.9 		
Total Assets		537.0 			42.0 			0.6 			579.6 			(221.5)			358.1 		
													
Current Risk Management Liabilities		183.1 			40.6 			5.3 			229.0 			(166.6)			62.4 		
Long-term Risk Management Liabilities		239.0 			57.0 			— 			296.0 			(63.6)			232.4 		
Total Liabilities		422.1 			97.6 			5.3 			525.0 			(230.2)			294.8 		
													
Total MTM Derivative Contract Net Assets (Liabilities)		$	114.9 			$	(55.6)			$	(4.7)			$	54.6 			$	8.7 			$	63.3 		

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 		

179

AEP Texas
Fair Value of Derivative Instruments
September 30, 2020

		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	— 			$	— 			$	— 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		— 			— 			— 		
							
Current Risk Management Liabilities		0.2 			(0.1)			0.1 		
Long-term Risk Management Liabilities		— 			— 			— 		
Total Liabilities		0.2 			(0.1)			0.1 		
							
Total MTM Derivative Contract Net Assets (Liabilities)		$	(0.2)			$	0.1 			$	(0.1)		

December 31, 2019

		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	— 			$	— 			$	— 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		— 			— 			— 		
							
Current Risk Management Liabilities		— 			— 			— 		
Long-term Risk Management Liabilities		— 			— 			— 		
Total Liabilities		— 			— 			— 		
							
Total MTM Derivative Contract Net Assets		$	— 			$	— 			$	— 		

APCo
Fair Value of Derivative Instruments
September 30, 2020

		Risk Management		Hedging		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Interest Rate (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	49.6 			$	0.6 			$	(19.5)			$	30.7 		
Long-term Risk Management Assets		1.6 			— 			(1.5)			0.1 		
Total Assets		51.2 			0.6 			(21.0)			30.8 		
									
Current Risk Management Liabilities		20.7 			5.3 			(20.4)			5.6 		
Long-term Risk Management Liabilities		1.8 			— 			(1.6)			0.2 		
Total Liabilities		22.5 			5.3 			(22.0)			5.8 		
									
Total MTM Derivative Contract Net Assets (Liabilities)		$	28.7 			$	(4.7)			$	1.0 			$	25.0 		

December 31, 2019

		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	124.4 			$	(85.0)			$	39.4 		
Long-term Risk Management Assets		0.9 			(0.8)			0.1 		
Total Assets		125.3 			(85.8)			39.5 		
							
Current Risk Management Liabilities		86.2 			(84.3)			1.9 		
Long-term Risk Management Liabilities		0.7 			(0.7)			— 		
Total Liabilities		86.9 			(85.0)			1.9 		
							
Total MTM Derivative Contract Net Assets (Liabilities)		$	38.4 			$	(0.8)			$	37.6 		
180

I&M
Fair Value of Derivative Instruments
September 30, 2020

		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	16.5 			$	(12.4)			$	4.1 		
Long-term Risk Management Assets		1.0 			(1.0)			— 		
Total Assets		17.5 			(13.4)			4.1 		
							
Current Risk Management Liabilities		13.1 			(12.9)			0.2 		
Long-term Risk Management Liabilities		1.1 			(1.0)			0.1 		
Total Liabilities		14.2 			(13.9)			0.3 		
							
Total MTM Derivative Contract Net Assets		$	3.3 			$	0.5 			$	3.8 		

December 31, 2019

		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	66.9 			$	(57.1)			$	9.8 		
Long-term Risk Management Assets		0.5 			(0.4)			0.1 		
Total Assets		67.4 			(57.5)			9.9 		
							
Current Risk Management Liabilities		55.2 			(54.7)			0.5 		
Long-term Risk Management Liabilities		0.4 			(0.4)			— 		
Total Liabilities		55.6 			(55.1)			0.5 		
							
Total MTM Derivative Contract Net Assets (Liabilities)		$	11.8 			$	(2.4)			$	9.4 		

OPCo
Fair Value of Derivative Instruments
September 30, 2020

		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	— 			$	— 			$	— 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		— 			— 			— 		
							
Current Risk Management Liabilities		8.3 			(0.1)			8.2 		
Long-term Risk Management Liabilities		105.1 			— 			105.1 		
Total Liabilities		113.4 			(0.1)			113.3 		
							
Total MTM Derivative Contract Net Assets (Liabilities)		$	(113.4)			$	0.1 			$	(113.3)		

December 31, 2019

		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	— 			$	— 			$	— 		
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)		
181

PSO
Fair Value of Derivative Instruments
September 30, 2020

		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	16.6 			$	— 			$	16.6 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		16.6 			— 			16.6 		
							
Current Risk Management Liabilities		0.6 			(0.1)			0.5 		
Long-term Risk Management Liabilities		— 			— 			— 		
Total Liabilities		0.6 			(0.1)			0.5 		
							
Total MTM Derivative Contract Net Assets		$	16.0 			$	0.1 			$	16.1 		

December 31, 2019

		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	16.3 			$	(0.5)			$	15.8 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		16.3 			(0.5)			15.8 		
							
Current Risk Management Liabilities		0.5 			(0.5)			— 		
Long-term Risk Management Liabilities		— 			— 			— 		
Total Liabilities		0.5 			(0.5)			— 		
							
Total MTM Derivative Contract Net Assets		$	15.8 			$	— 			$	15.8 		

SWEPCo
Fair Value of Derivative Instruments
September 30, 2020

		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	4.5 			$	— 			$	4.5 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		4.5 			— 			4.5 		
							
Current Risk Management Liabilities		0.2 			(0.1)			0.1 		
Long-term Risk Management Liabilities		0.7 			— 			0.7 		
Total Liabilities		0.9 			(0.1)			0.8 		
							
Total MTM Derivative Contract Net Assets		$	3.6 			$	0.1 			$	3.7 		

December 31, 2019

		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	6.5 			$	(0.1)			$	6.4 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		6.5 			(0.1)			6.4 		
							
Current Risk Management Liabilities		2.0 			(0.1)			1.9 		
Long-term Risk Management Liabilities		3.1 			— 			3.1 		
Total Liabilities		5.1 			(0.1)			5.0 		
							
Total MTM Derivative Contract Net Assets		$	1.4 			$	— 			$	1.4 		

(a)Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
(b)Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
(c)All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
182

The tables below present the Registrants’ activity of derivative risk management contracts:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
Three Months Ended September 30, 2020

Location of Gain (Loss)		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Vertically Integrated Utilities Revenues		$	0.5 			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		
	
Generation & Marketing Revenues		11.5 			— 			— 			— 			— 			— 			— 		
Electric Generation, Transmission and Distribution Revenues		— 			— 			0.3 			— 			— 			— 			— 		

Purchased Electricity for Resale		0.3 			— 			0.2 			0.1 			— 			— 			— 		
Other Operation		(0.4)			(0.1)			(0.1)			(0.1)			(0.1)			(0.1)			(0.1)		
Maintenance		(0.8)			(0.2)			(0.1)			(0.1)			(0.2)			— 			(0.1)		
Regulatory Assets (a)		7.9 			0.2 			0.4 			0.2 			4.4 			(0.4)			2.9 		
Regulatory Liabilities (a)		17.0 			— 			3.8 			2.6 			1.7 			3.1 			2.0 		
Total Gain (Loss) on Risk Management Contracts		$	36.0 			$	(0.1)			$	4.5 			$	2.7 			$	5.8 			$	2.6 			$	4.7 		

Three Months Ended September 30, 2019

Location of Gain (Loss)		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Vertically Integrated Utilities Revenues		$	0.5 			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		
	
Generation & Marketing Revenues		21.0 			— 			— 			— 			— 			— 			— 		
Electric Generation, Transmission and Distribution Revenues		— 			— 			0.2 			0.2 			— 			— 			— 		

Purchased Electricity for Resale		0.4 			— 			0.3 			— 			— 			— 			— 		
Other Operation		(0.1)			— 			(0.1)			(0.1)			(0.1)			(0.1)			— 		
Maintenance		(0.2)			— 			— 			(0.1)			— 			— 			— 		
Regulatory Assets (a)		(4.8)			(0.2)			0.2 			— 			(2.6)			(0.1)			(1.6)		
Regulatory Liabilities (a)		26.3 			— 			10.0 			3.2 			— 			4.3 			4.5 		
Total Gain (Loss) on Risk Management Contracts		$	43.1 			$	(0.2)			$	10.6 			$	3.2 			$	(2.7)			$	4.1 			$	2.9 		

Nine Months Ended September 30, 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		11.1 			— 			— 			— 			— 			— 			— 		
Electric Generation, Transmission and Distribution Revenues		— 			— 			0.4 			0.1 			— 			— 			0.1 		

Purchased Electricity for Resale		1.2 			— 			1.0 			0.1 			— 			— 			— 		
Other Operation		(1.4)			(0.4)			(0.2)			(0.2)			(0.3)			(0.2)			(0.2)		
Maintenance		(2.2)			(0.6)			(0.3)			(0.2)			(0.4)			(0.2)			(0.3)		
Regulatory Assets (a)		(8.5)			(0.3)			(0.1)			(0.2)			(9.9)			(0.6)			2.2 		
Regulatory Liabilities (a)		80.9 			— 			16.2 			8.8 			8.4 			23.9 			14.8 		
Total Gain (Loss) on Risk Management Contracts		$	81.9 			$	(1.3)			$	17.0 			$	8.4 			$	(2.2)			$	22.9 			$	16.6 		
183

Nine Months Ended September 30, 2019

Location of Gain (Loss)		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Vertically Integrated Utilities Revenues		$	1.0 			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		
	
Generation & Marketing Revenues		27.2 			— 			— 			— 			— 			— 			— 		
Electric Generation, Transmission and Distribution Revenues		— 			— 			0.2 			0.5 			— 			— 			0.1 		

Purchased Electricity for Resale		1.6 			— 			1.4 			0.1 			— 			— 			— 		
Other Operation		(0.6)			(0.1)			(0.1)			(0.1)			(0.2)			(0.1)			(0.1)		
Maintenance		(0.6)			(0.1)			(0.1)			(0.1)			(0.1)			— 			(0.1)		
Regulatory Assets (a)		(19.4)			0.3 			0.4 			0.2 			(19.8)			0.9 			(0.4)		
Regulatory Liabilities (a)		64.5 			— 			(5.3)			17.2 			— 			26.6 			22.9 		
Total Gain (Loss) on Risk Management Contracts		$	73.7 			$	0.1 			$	(3.5)			$	17.8 			$	(20.1)			$	27.4 			$	22.4 		

(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

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.

184

The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:

		Carrying Amount of the Hedged Liabilities		Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities	
		September 30, 2020		December 31, 2019		September 30, 2020		December 31, 2019	
		(in millions)	
Long-term Debt (a) (b)		$	(551.9)			$	(510.8)			$	(55.2)			$	(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 $(55) million and $0 as of September 30, 2020 and December 31, 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:

	Three Months Ended September 30,		Nine Months Ended September 30,	
	2020		2019		2020		2019	
	(in millions)	
Gain (Loss) on Interest Rate Contracts:								
Gain on Fair Value Hedging Instruments (a)	$	— 			$	13.2 			$	42.6 			$	42.5 		
Loss on Fair Value Portion of Long-term Debt (a)	— 			(13.2)			(42.6)			(42.5)		

(a)Gain (Loss) is included in Interest Expense on the statements of income.

In June 2020, AEP terminated a $500 million notional amount interest rate swap resulting in the discontinuance of the hedging relationship. A gain of $57 million on the fair value of the hedging instrument was settled in cash and recorded within operating activities on the 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 three and nine months ended September 30, 2020 and 2019, AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 2020 and 2019, 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 three and nine months ended September 30, 2020, AEP and APCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the three and nine months ended September 30, 2019, AEP applied cash flow hedging to outstanding interest rate derivatives and the Registrant Subsidiaries did not.

185

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

		September 30, 2020		December 31, 2019	
		Commodity		Interest Rate		Commodity		Interest Rate	
		(in millions)	
AOCI Gain (Loss) Net of Tax		$	(45.1)			$	(52.3)			$	(103.5)			$	(11.5)		
Portion Expected to be Reclassed to Net Income During the Next Twelve Months		(13.9)			(5.3)			(51.7)			(2.1)		

As of September 30, 2020 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 126 months and 123 months for commodity and interest rate hedges, respectively.

Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets

		September 30, 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		$	(2.6)			$	(1.1)			$	(3.4)			$	(1.1)		
APCo		(3.5)			0.6 			0.9 			0.9 		
I&M		(8.7)			(1.6)			(9.9)			(1.6)		
	
PSO		0.3 			0.3 			1.1 			1.0 		
SWEPCo		(0.7)			(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 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.

186

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 September 30, 2020 and December 31, 2019, respectively.

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:

		September 30, 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		$	189.7 			$	— 			$	162.3 		
APCo		5.7 			— 			5.3 		
I&M		0.3 			— 			— 		

SWEPCo		0.9 			— 			0.9 		

		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 		

	
187

10.  FAIR VALUE MEASUREMENTS

The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.

Fair Value Hierarchy and Valuation Techniques

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 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 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 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.
188

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:

		September 30, 2020		December 31, 2019	
Company		Book Value		Fair Value		Book Value		Fair Value	
		(in millions)	
AEP (a)		$	30,067.1 			$	35,603.2 			$	26,725.5 			$	30,172.0 		
AEP Texas		4,854.7 			5,590.0 			4,558.4 			4,981.5 		
AEPTCo		3,947.9 			4,859.5 			3,427.3 			3,868.0 		
APCo		4,833.3 			6,167.6 			4,363.8 			5,253.1 		
I&M		2,981.9 			3,637.4 			3,050.2 			3,453.8 		
OPCo		2,429.9 			3,137.5 			2,082.0 			2,554.3 		
PSO		1,373.7 			1,694.9 			1,386.2 			1,603.3 		
SWEPCo		2,637.3 			3,119.2 			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 $1.6 billion and $871 million as of September 30, 2020 and December 31, 2019, respectively. See “Equity Units” section of Note 12 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.

The following is a summary of Other Temporary Investments:

		September 30, 2020	
				Gross		Gross			
				Unrealized		Unrealized		Fair	
Other Temporary Investments		Cost		Gains		Losses		Value	
		(in millions)	
Restricted Cash and Other Cash Deposits (a)		$	79.6 			$	— 			$	— 			$	79.6 		
Fixed Income Securities – Mutual Funds (b)		127.9 			2.9 			— 			130.8 		
Equity Securities – Mutual Funds		30.2 			22.5 			— 			52.7 		
Total Other Temporary Investments		$	237.7 			$	25.4 			$	— 			$	263.1 		

		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.

189

The following table provides the activity for fixed income and equity securities within Other Temporary Investments:

 	Three Months Ended September 30,		Nine Months Ended September 30,	
 	2020		2019		2020		2019	
	(in millions)	
Proceeds from Investment Sales	$	5.1 			$	2.8 			$	35.9 			$	2.8 		
Purchases of Investments	22.5 			26.9 			39.5 			35.8 		
Gross Realized Gains on Investment Sales	0.2 			— 			2.4 			— 		
Gross Realized Losses on Investment Sales	— 			— 			0.2 			— 		

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (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 external investment managers who 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 securities in the trust funds as available-for-sale due to their long-term purpose. Available-for-sale classification only applies to investment in debt securities in accordance with ASU 2016-01. Additionally, ASU 2016-01 requires changes in fair value of equity securities to be recognized in earnings. However, due to the regulatory treatment described below, this is not applicable for I&M’s trust fund securities.

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.

190

The following is a summary of nuclear trust fund investments:

 	September 30, 2020		December 31, 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	$	33.7 			$	— 			$	— 			$	15.3 			$	— 			$	— 		
Fixed Income Securities:												
United States Government	1,039.2 			112.3 			(5.8)			1,112.5 			55.5 			(6.1)		
Corporate Debt	85.6 			8.9 			(1.5)			72.4 			5.3 			(1.6)		
State and Local Government	123.9 			1.5 			(0.3)			7.6 			0.7 			(0.2)		
Subtotal Fixed Income Securities	1,248.7 			122.7 			(7.6)			1,192.5 			61.5 			(7.9)		
Equity Securities - Domestic (a)	1,793.5 			1,165.8 			— 			1,767.9 			1,144.4 			— 		
Spent Nuclear Fuel and Decommissioning Trusts	$	3,075.9 			$	1,288.5 			$	(7.6)			$	2,975.7 			$	1,205.9 			$	(7.9)		

(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.2 billion and $1.1 billion and unrealized losses of $17 million and $5 million as of September 30, 2020 and December 31, 2019, respectively.

The following table provides the securities activity within the decommissioning and SNF trusts:

		Three Months Ended September 30,		Nine Months Ended September 30,	
 		2020		2019		2020		2019	
 		(in millions)	
Proceeds from Investment Sales		$	316.6 			$	671.9 			$	1,257.1 			$	871.4 		
Purchases of Investments		318.6 			689.1 			1,290.0 			915.7 		
Gross Realized Gains on Investment Sales		3.4 			10.9 			25.4 			26.6 		
Gross Realized Losses on Investment Sales		0.5 			7.1 			25.2 			15.1 		

The base cost of fixed income securities was $1.1 billion and $1.1 billion as of September 30, 2020 and December 31, 2019, respectively.  The base cost of equity securities was $628 million and $623 million as of September 30, 2020 and December 31, 2019, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2020 was as follows:

	Fair Value of Fixed	
	Income Securities	
	(in millions)	
Within 1 year	$	291.6 		
After 1 year through 5 years	355.9 		
After 5 years through 10 years	255.1 		
After 10 years	346.1 		
Total	$	1,248.7 		
191

Fair Value Measurements of Financial Assets and Liabilities

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2020

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	

	
Other Temporary Investments											
Restricted Cash and Other Cash Deposits (a)		$	66.3 			$	— 			$	— 			$	13.3 			$	79.6 		
Fixed Income Securities – Mutual Funds		130.8 			— 			— 			— 			130.8 		
Equity Securities – Mutual Funds (b)		52.7 			— 			— 			— 			52.7 		
Total Other Temporary Investments		249.8 			— 			— 			13.3 			263.1 		
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (d)		3.2 			247.1 			280.3 			(185.3)			345.3 		
Cash Flow Hedges:											
Commodity Hedges (c)		— 			36.1 			4.3 			(28.2)			12.2 		
Interest Rate Hedges		— 			0.6 			— 			— 			0.6 		
	
Total Risk Management Assets		3.2 			283.8 			284.6 			(213.5)			358.1 		
											
Spent Nuclear Fuel and Decommissioning Trusts											
Cash and Cash Equivalents (e)		24.7 			— 			— 			9.0 			33.7 		
Fixed Income Securities:											
United States Government		— 			1,039.2 			— 			— 			1,039.2 		
Corporate Debt		— 			85.6 			— 			— 			85.6 		
State and Local Government		— 			123.9 			— 			— 			123.9 		
Subtotal Fixed Income Securities		— 			1,248.7 			— 			— 			1,248.7 		
Equity Securities – Domestic (b)		1,793.5 			— 			— 			— 			1,793.5 		
Total Spent Nuclear Fuel and Decommissioning Trusts		1,818.2 			1,248.7 			— 			9.0 			3,075.9 		
											
Total Assets		$	2,071.2 			$	1,532.5 			$	284.6 			$	(191.2)			$	3,697.1 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (d)		$	3.4 			$	239.1 			$	173.2 			$	(194.0)			$	221.7 		
Cash Flow Hedges:											
Commodity Hedges (c)		— 			90.7 			5.3 			(28.2)			67.8 		
Interest Rate Hedges		— 			5.3 			— 			— 			5.3 		
	
Total Risk Management Liabilities		$	3.4 			$	335.1 			$	178.5 			$	(222.2)			$	294.8 		
192

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis
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 		

193

AEP Texas
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2020

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Restricted Cash for Securitized Funding		$	44.8 			$	— 			$	— 			$	— 			$	44.8 		

	

	
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c)		$	— 			$	0.2 			$	— 			$	(0.1)			$	0.1 		

December 31, 2019

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Restricted Cash for Securitized Funding		$	154.7 			$	— 			$	— 			$	— 			$	154.7 		

	

	

	

APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2020

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Restricted Cash for Securitized Funding		$	9.3 			$	— 			$	— 			$	— 			$	9.3 		
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		— 			20.4 			30.1 			(20.3)			30.2 		
Cash Flow Hedges:											
Interest Rate Hedges		— 			0.6 			— 			— 			0.6 		
Total Risk Management Assets		— 			21.0 			30.1 			(20.3)			30.8 		
											
Total Assets		$	9.3 			$	21.0 			$	30.1 			$	(20.3)			$	40.1 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	21.2 			$	0.5 			$	(21.2)			$	0.5 		
Cash Flow Hedges:											
Interest Rate Hedges		— 			5.3 			— 			— 			5.3 		
Total Risk Management Liabilities		$	— 			$	26.5 			$	0.5 			$	(21.2)			$	5.8 		

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 		
194

I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2020

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	12.9 			$	4.1 			$	(12.9)			$	4.1 		
											
Spent Nuclear Fuel and Decommissioning Trusts											
Cash and Cash Equivalents (e)		24.7 			— 			— 			9.0 			33.7 		
Fixed Income Securities:											
United States Government		— 			1,039.2 			— 			— 			1,039.2 		
Corporate Debt		— 			85.6 			— 			— 			85.6 		
State and Local Government		— 			123.9 			— 			— 			123.9 		
Subtotal Fixed Income Securities		— 			1,248.7 			— 			— 			1,248.7 		
Equity Securities - Domestic (b)		1,793.5 			— 			— 			— 			1,793.5 		
Total Spent Nuclear Fuel and Decommissioning Trusts		1,818.2 			1,248.7 			— 			9.0 			3,075.9 		
											
Total Assets		$	1,818.2 			$	1,261.6 			$	4.1 			$	(3.9)			$	3,080.0 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	13.4 			$	0.3 			$	(13.4)			$	0.3 		

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 		
195

OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2020

		Level 1		Level 2		Level 3		Other		Total	

	

	

	
Liabilities:		(in millions)	
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	0.2 			$	113.2 			$	(0.1)			$	113.3 		

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
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2020

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	16.6 			$	— 			$	16.6 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	0.1 			$	0.5 			$	(0.1)			$	0.5 		

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)			$	— 		
196

SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2020

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	

	
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	4.4 			$	0.1 			$	4.5 		

											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	0.1 			$	0.7 			$	— 			$	0.8 		

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 September 30, 2020 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(6) million in 2020, $3 million in periods 2021-2023, $4 million in periods 2024-2025 and $7 million in periods 2026-2033; Level 3 matures $35 million in 2020, $63 million in periods 2021-2023, $21 million in periods 2024-2025 and $(12) million in periods 2026-2033.  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 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is 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.

197

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:

Three Months Ended September 30, 2020		AEP		APCo		I&M		OPCo		PSO		SWEPCo	
 		(in millions)	
Balance as of June 30, 2020		$	111.6 			$	36.5 			$	4.5 			$	(117.4)			$	23.8 			$	3.3 		
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		18.7 			6.4 			3.3 			— 			3.0 			1.5 		
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)		6.5 			— 			— 			— 			— 			— 		
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)		2.6 			— 			— 			— 			— 			— 		
Settlements		(37.0)			(11.1)			(5.0)			1.3 			(10.3)			(3.5)		
Transfers into Level 3 (d) (e)		(1.0)			— 			— 			— 			— 			— 		
Transfers out of Level 3 (e)		1.1 			— 			— 			— 			— 			— 		
Changes in Fair Value Allocated to Regulated Jurisdictions (f)		3.6 			(2.2)			1.0 			2.9 			(0.4)			2.4 		
Balance as of September 30, 2020		$	106.1 			$	29.6 			$	3.8 			$	(113.2)			$	16.1 			$	3.7 		
													
Three Months Ended September 30, 2019		AEP		APCo		I&M		OPCo		PSO		SWEPCo	
 		(in millions)	
Balance as of June 30, 2019		$	112.7 			$	68.5 			$	12.3 			$	(111.5)			$	27.8 			$	8.5 		
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		30.2 			13.8 			3.1 			— 			4.1 			3.6 		
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)		2.9 			— 			— 			— 			— 			— 		
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)		22.1 			— 			— 			— 			— 			— 		
Settlements		(67.4)			(28.1)			(7.2)			1.1 			(11.2)			(6.7)		
Transfers into Level 3 (d) (e)		3.5 			— 			— 			— 			— 			— 		
Transfers out of Level 3 (e)		6.6 			— 			— 			— 			— 			— 		
Changes in Fair Value Allocated to Regulated Jurisdictions (f)		(0.3)			1.3 			0.7 			(2.1)			0.9 			(0.5)		
Balance as of September 30, 2019		$	110.3 			$	55.5 			$	8.9 			$	(112.5)			$	21.6 			$	4.9 		
													
Nine Months Ended September 30, 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)		39.6 			13.1 			2.4 			(1.2)			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)		(2.4)			— 			— 			— 			— 			— 		
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)		21.7 			— 			— 			— 			— 			— 		
Settlements		(115.3)			(51.4)			(8.5)			6.4 			(27.6)			(6.9)		
Transfers into Level 3 (d) (e)		(1.1)			— 			— 			— 			— 			— 		
Transfers out of Level 3 (e)		5.6 			0.7 			0.4 			— 			— 			— 		
Changes in Fair Value Allocated to Regulated Jurisdictions (f)		48.1 			29.5 			3.7 			(14.8)			16.0 			6.4 		
Balance as of September 30, 2020		$	106.1 			$	29.6 			$	3.8 			$	(113.2)			$	16.1 			$	3.7 		
													
198

																																							
Nine Months Ended September 30, 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)		14.6 			(14.1)			4.6 			(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)		32.9 			— 			— 			— 			— 			— 		
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)		(42.8)			— 			— 			— 			— 			— 		
Settlements		(114.6)			(41.9)			(12.6)			4.6 			(23.0)			(10.1)		
Transfers into Level 3 (d) (e)		0.4 			— 			— 			— 			— 			— 		
Transfers out of Level 3 (e)		1.4 			(0.7)			(0.4)			— 			— 			— 		
Changes in Fair Value Allocated to Regulated Jurisdictions (f)		87.2 			54.4 			8.4 			(16.8)			21.6 			6.7 		
Balance as of September 30, 2019		$	110.3 			$	55.5 			$	8.9 			$	(112.5)			$	21.6 			$	4.9 		

(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.

199

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:

AEP
Significant Unobservable Inputs
September 30, 2020

					Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	219.2 			$	173.0 			Discounted Cash Flow		Forward Market Price (a)		$	3.36 			$	111.42 			$	32.62 		
Natural Gas Contracts	— 			0.6 			Discounted Cash Flow		Forward Market Price (b)		1.79 			3.06 			2.61 		
FTRs	65.4 			4.9 			Discounted Cash Flow		Forward Market Price (a)		(6.15)			10.66 			0.23 		
Total	$	284.6 			$	178.5 												

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 												
200

APCo
Significant Unobservable Inputs
September 30, 2020

					Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	0.8 			$	0.5 			Discounted Cash Flow		Forward Market Price		$	9.56 			$	41.80 			$	27.25 		
FTRs	29.3 			— 			Discounted Cash Flow		Forward Market Price		(0.81)			6.57 			1.09 		
Total	$	30.1 			$	0.5 												

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
Significant Unobservable Inputs
September 30, 2020

							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	0.5 			$	0.3 			Discounted Cash Flow		Forward Market Price		$	9.56 			$	41.80 			$	27.25 		
FTRs	3.6 			— 			Discounted Cash Flow		Forward Market Price		(2.68)			4.24 			0.41 		
Total	$	4.1 			$	0.3 												

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 												
201

OPCo
Significant Unobservable Inputs
September 30, 2020

							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	— 			$	113.2 			Discounted Cash Flow		Forward Market Price		$	11.68 			$	47.28 			$	28.31 		

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
Significant Unobservable Inputs
September 30, 2020

							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
FTRs	$	16.6 			$	0.5 			Discounted Cash Flow		Forward Market Price		$	(5.98)			$	0.70 			$	(1.85)		

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)		
202

SWEPCo
Significant Unobservable Inputs
September 30, 2020

							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input		Low		High		Average (c)	
	(in millions)											
Natural Gas Contracts	$	— 			$	0.6 			Discounted Cash Flow		Forward Market Price (b)		$	1.79 			$	3.02 			$	2.54 		
FTRs	4.4 			0.1 			Discounted Cash Flow		Forward Market Price (a)		(5.98)			0.70 			(1.85)		
Total	$	4.4 			$	0.7 												

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.

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 and FTRs for the Registrants as of September 30, 2020 and December 31, 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)	
203

11.  INCOME TAXES

The disclosures in this note apply to all Registrants unless indicated otherwise.

Federal Legislation

In March 2020, the CARES Act was signed into law.  The CARES Act includes tax relief provisions such as: (a) an Alternative Minimum Tax (AMT) Credit Refund, (b) a 5-year net operating losses (NOL) carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. In May 2020, the House passed the "Health and Economic Recovery Omnibus Emergency Solutions Act" (HEROES Act) pending decision by the Senate. If enacted, the HEROES Act would disallow NOL carrybacks to any tax year beginning before January 1, 2018.  Pursuant to the CARES Act, AEP, APCo and OPCo requested and in July received a $20 million, $7 million and $9 million, respectively, refund of AMT credit. 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 an 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 $52 million, recorded discretely, primarily at the Generation & Marketing segment. On October 1, 2020, after AEP filed its request with the IRS, the House passed a revised version of the HEROES Act; which similar to the original legislation would disallow NOL carryback to years prior to 2018. Management will continue to monitor the potential impact of this legislation. The Registrants are currently deferring 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.

Effective Tax Rates (ETR)

The Registrants’ interim ETR reflect the estimated annual ETR for 2020 and 2019, adjusted for tax expense associated with certain discrete items.

The Registrants include the amortization of Excess ADIT not subject to normalization requirements in the annual estimated ETR when regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers over multiple interim periods.  Certain regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers in a single period (e.g. by applying the Excess ADIT not subject to normalization requirements against an existing regulatory asset balance) and in these circumstances, the Registrants recognize the tax benefit discretely in the period recorded. The annual amount of Excess ADIT approved by the Registrant’s regulatory commissions may not impact the ETR ratably during each interim period due to the variability of pretax book income between interim periods and the application of an annual estimated ETR.

The ETR for each of the Registrants are included in the following tables:

		Three Months Ended September 30, 2020	
		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
U.S. Federal Statutory Rate		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%	
Increase (decrease) due to:																	
State Income Tax, net of Federal Benefit		2.7 	%		2.0 	%		2.9 	%		3.1 	%		3.4 	%		0.8 	%		4.6 	%		2.4 	%	
Tax Reform Excess ADIT Reversal		(11.0)	%		(14.6)	%		0.4 	%		(22.0)	%		(16.7)	%		(6.7)	%		(20.3)	%		(7.3)	%	
Production and Investment Tax Credits		(4.6)	%		(0.5)	%		— 	%		— 	%		(1.6)	%		— 	%		(1.1)	%		(0.5)	%	
Flow Through		0.5 	%		0.2 	%		0.5 	%		1.6 	%		0.2 	%		0.9 	%		0.2 	%		(1.2)	%	
AFUDC Equity		(1.5)	%		(3.5)	%		(2.6)	%		(1.1)	%		(0.9)	%		(0.9)	%		(0.6)	%		(0.3)	%	
Parent Company Loss Benefit		— 	%		— 	%		(0.9)	%		(3.1)	%		(3.7)	%		(0.3)	%		(1.7)	%		(2.0)	%	
Discrete Tax Adjustments		(7.4)	%		(3.6)	%		(0.2)	%		(6.6)	%		2.3 	%		8.4 	%		(0.6)	%		(0.6)	%	
Other		0.1 	%		0.3 	%		0.1 	%		— 	%		— 	%		0.3 	%		0.1 	%		(0.6)	%	
Effective Income Tax Rate		(0.2)	%		1.3 	%		21.2 	%		(7.1)	%		4.0 	%		23.5 	%		1.6 	%		10.9 	%	
																	
204

																																																			
		Three Months Ended September 30, 2019	
		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
U.S. Federal Statutory Rate		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%	
Increase (decrease) due to:																	
State Income Tax, net of Federal Benefit		2.6 	%		1.4 	%		3.1 	%		3.0 	%		(0.1)	%		0.4 	%		4.8 	%		2.4 	%	
Tax Reform Excess ADIT Reversal		(11.9)	%		(6.1)	%		1.4 	%		(26.6)	%		(17.3)	%		(6.9)	%		(16.5)	%		(19.5)	%	
Production and Investment Tax Credits		(3.7)	%		(0.2)	%		— 	%		— 	%		(2.0)	%		— 	%		(1.4)	%		(0.9)	%	
Flow Through		0.4 	%		— 	%		0.1 	%		3.8 	%		(0.7)	%		1.0 	%		0.7 	%		(0.5)	%	
AFUDC Equity		(1.5)	%		(1.1)	%		(2.6)	%		(1.3)	%		(1.7)	%		(1.7)	%		(0.3)	%		(0.9)	%	
Parent Company Loss Benefit		— 	%		(0.1)	%		(1.3)	%		(1.1)	%		(1.0)	%		0.4 	%		(1.8)	%		(1.8)	%	
Discrete Tax Adjustments		(1.7)	%		— 	%		(0.1)	%		(2.4)	%		(1.3)	%		1.7 	%		— 	%		— 	%	
Other		— 	%		0.2 	%		0.3 	%		(0.3)	%		0.4 	%		(2.0)	%		(0.1)	%		(0.4)	%	
Effective Income Tax Rate		5.2 	%		15.1 	%		21.9 	%		(3.9)	%		(2.7)	%		13.9 	%		6.4 	%		(0.6)	%	
																	
		Nine Months Ended September 30, 2020	
		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
U.S. Federal Statutory Rate		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%	
Increase (decrease) due to:																	
State Income Tax, net of Federal Benefit		2.6 	%		1.8 	%		2.9 	%		3.1 	%		3.4 	%		0.7 	%		4.6 	%		2.3 	%	
Tax Reform Excess ADIT Reversal		(12.1)	%		(23.4)	%		0.4 	%		(20.8)	%		(16.7)	%		(8.8)	%		(20.3)	%		(11.5)	%	
Production and Investment Tax Credits		(4.5)	%		(0.5)	%		— 	%		— 	%		(1.6)	%		— 	%		(1.1)	%		(0.5)	%	
Flow Through		0.5 	%		0.1 	%		0.5 	%		1.6 	%		0.2 	%		0.9 	%		0.2 	%		(1.2)	%	
AFUDC Equity		(1.5)	%		(3.2)	%		(2.6)	%		(1.1)	%		(0.9)	%		(0.9)	%		(0.6)	%		(0.3)	%	
Parent Company Loss Benefit		— 	%		— 	%		(0.9)	%		(3.1)	%		(3.7)	%		(0.3)	%		(1.7)	%		(1.9)	%	
Discrete Tax Adjustments		(3.0)	%		(1.6)	%		(0.1)	%		(2.3)	%		1.8 	%		2.6 	%		(0.4)	%		(0.3)	%	
Other		0.2 	%		0.4 	%		(0.1)	%		(0.1)	%		(0.1)	%		0.2 	%		0.1 	%		(0.4)	%	
Effective Income Tax Rate		3.2 	%		(5.4)	%		21.1 	%		(1.7)	%		3.4 	%		15.4 	%		1.8 	%		7.2 	%	

																	
		Nine Months Ended September 30, 2019	
		AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
U.S. Federal Statutory Rate		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%		21.0 	%	
Increase (decrease) due to:																	
State Income Tax, net of Federal Benefit		2.1 	%		1.5 	%		3.0 	%		3.3 	%		1.2 	%		0.7 	%		4.7 	%		1.8 	%	
Tax Reform Excess ADIT Reversal		(16.7)	%		(43.9)	%		0.7 	%		(40.2)	%		(17.3)	%		(7.4)	%		(18.2)	%		(18.7)	%	
Production and Investment Tax Credits		(3.6)	%		(0.5)	%		— 	%		— 	%		(2.0)	%		— 	%		(1.5)	%		(0.8)	%	
Flow Through		0.1 	%		0.1 	%		0.2 	%		0.7 	%		(1.8)	%		0.7 	%		0.6 	%		(0.6)	%	
AFUDC Equity		(1.5)	%		(1.3)	%		(2.5)	%		(1.1)	%		(1.9)	%		(1.0)	%		(0.3)	%		(0.9)	%	
Parent Company Loss Benefit		— 	%		(1.0)	%		(1.1)	%		(1.9)	%		(1.5)	%		(0.7)	%		(1.8)	%		(1.5)	%	
Discrete Tax Adjustments		— 	%		(1.3)	%		(0.6)	%		(0.8)	%		0.2 	%		0.5 	%		— 	%		(0.2)	%	
Other		0.3 	%		0.1 	%		— 	%		(0.1)	%		— 	%		0.4 	%		0.1 	%		(0.1)	%	
Effective Income Tax Rate		1.7 	%		(25.3)	%		20.7 	%		(19.1)	%		(2.1)	%		14.2 	%		4.6 	%		— 	%	

Federal and State Income Tax Audit Status

AEP and subsidiaries are no longer subject to U.S. federal examination by the IRS for all years through 2015. During 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 net operating loss carryback to 2015 that originated in the 2017 return. The IRS may examine only the amended items on the 2014 and 2015 federal returns.
205

12.  FINANCING ACTIVITIES

The disclosures in this note apply to all Registrants, unless indicated otherwise.

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.

Long-term Debt Outstanding (Applies to AEP)

The following table details long-term debt outstanding, net of issuance costs and premiums or discounts:

Type of Debt		September 30, 2020		December 31, 2019	
 		(in millions)	
Senior Unsecured Notes		$	24,125.4 			$	21,180.7 		
Pollution Control Bonds		1,936.1 			1,998.8 		
Notes Payable		161.3 			234.3 		
Securitization Bonds		751.6 			1,025.1 		
Spent Nuclear Fuel Obligation (a)		281.1 			279.8 		
Junior Subordinated Notes (b)		1,622.1 			787.8 		
Other Long-term Debt		1,189.5 			1,219.0 		
Total Long-term Debt Outstanding		30,067.1 			26,725.5 		
Long-term Debt Due Within One Year		1,911.6 			1,598.7 		
Long-term Debt		$	28,155.5 			$	25,126.8 		

(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation were $326 million and $323 million as of September 30, 2020 and December 31, 2019, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
(b)See “Equity Units” section below for additional information.

Long-term Debt Activity

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2020 are shown in the following tables:

				Principal		Interest			
Company		Type of Debt		Amount (a)		Rate		Due Date	
Issuances:		 		(in millions)		(%)			
AEP		Junior Subordinated Notes (b)		$	850.0 			1.30		2025	
AEP		Senior Unsecured Notes		400.0 			2.30		2030	
AEP		Senior Unsecured Notes		400.0 			3.25		2050	
AEP Texas		Pollution Control Bonds		60.0 			0.90		2023	
AEP Texas		Senior Unsecured Notes		600.0 			2.10		2030	
AEPTCo		Senior Unsecured Notes		525.0 			3.65		2050	
APCo		Pollution Control Bonds		65.4 			1.00		2025	
APCo		Senior Unsecured Notes		500.0 			3.70		2050	
OPCo		Senior Unsecured Notes		350.0 			2.60		2030	

	
									
Non-Registrant:									
KPCo		Other Long-term Debt		125.0 			Variable		2022	
Transource Energy		Other Long-term Debt		4.4 			Variable		2020	
Transource Energy		Other Long-term Debt		7.1 			Variable		2023	
Transource Energy		Senior Unsecured Notes		150.0 			2.75		2050	
Total Issuances				$	4,036.9 						

(a)Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
(b)See “Equity Units” section below for additional information.
206

																											
				Principal		Interest			
Company		Type of Debt		Amount Paid		Rate		Due Date	
Retirements and Principal Payments:				(in millions)		(%)			
AEP Texas		Pollution Control Bonds		$	50.6 			4.45		2020	
AEP Texas		Securitization Bonds		28.7 			1.98		2020	
AEP Texas		Securitization Bonds		202.6 			5.31		2020	
AEP Texas		Pollution Control Bonds		60.0 			1.75		2020	
AEP Texas		Securitization Bonds		0.2 			2.85		2024	
AEP Texas		Securitization Bonds		14.4 			2.06		2025	

APCo		Pollution Control Bonds		65.4 			1.70		2020	
APCo		Securitization Bonds		24.9 			2.01		2023	

	

	
I&M		Notes Payable		2.0 			Variable		2020	
I&M		Notes Payable		4.6 			Variable		2021	
I&M		Notes Payable		14.9 			Variable		2022	
I&M		Notes Payable		11.4 			Variable		2022	
I&M		Notes Payable		18.7 			Variable		2023	
I&M		Notes Payable		18.2 			Variable		2024	
I&M		Other Long-term Debt		1.3 			6.00		2025	
	
OPCo		Other Long-term Debt		0.1 			1.15		2028	
PSO		Pollution Control Bonds		12.7 			4.45		2020	
PSO		Other Long-term Debt		0.3 			3.00		2027	

SWEPCo		Other Long-term Debt		15.0 			Variable		2020	
SWEPCo		Other Long-term Debt		1.5 			4.68		2028	
SWEPCo		Notes Payable		3.2 			4.58		2032	
									
Non-Registrant:									
	
Transource Energy		Other Long-term Debt		148.6 			Variable		2023	
Transource Energy		Senior Unsecured Notes		1.2 			2.75		2050	

	

	
	
Total Retirements and Principal Payments				$	700.5 						

Long-term Debt Subsequent Events

In October 2020, I&M issued $70 million of Notes Payable related to DCC Fuel.

In October 2020, I&M retired $5 million of Notes Payable related to DCC Fuel.

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%.

207

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.

208

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 $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 0.9% of consolidated tangible net assets as of September 30, 2020. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreements.

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 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 Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings.

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.
209

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 September 30, 2020 and December 31, 2019 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets.  The Utility Money Pool participants’ activity and corresponding authorized borrowing limits for the nine months ended September 30, 2020 are described in the following table:

		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		September 30, 2020		Limit		
 		(in millions)	
AEP Texas		$	320.4 			$	313.4 			$	154.7 			$	167.4 			$	141.3 			$	500.0 			
AEPTCo		358.4 			259.7 			112.7 			59.1 			(84.3)			820.0 		(a)	
APCo		434.3 			189.0 			274.8 			74.6 			155.2 			500.0 			
I&M		218.6 			13.4 			115.3 			13.3 			(145.8)			500.0 			
OPCo		353.9 			32.8 			158.3 			25.2 			(215.9)			500.0 			
PSO		125.4 			57.1 			64.6 			28.4 			(77.8)			300.0 			
SWEPCo		178.9 			— 			113.6 			— 			(71.8)			350.0 			

(a)    Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.

The activity in the above table 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 September 30, 2020 and December 31, 2019 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the nine months ended September 30, 2020 is described in the following table:

		Maximum Loans	 	Average Loans	 	Loans to the Nonutility	
		to the Nonutility	 	to the Nonutility	 	Money Pool as of	
Company		Money Pool		Money Pool		September 30, 2020	
	(in millions)	
AEP Texas		$	7.5 			$	7.1 			$	7.1 		
SWEPCo		2.1 			2.1 			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 September 30, 2020 and December 31, 2019 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP and corresponding authorized borrowing limit for the nine months ended September 30, 2020 are described in the following table:

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	 	September 30, 2020		September 30, 2020		Borrowing Limit		
(in millions)	
$	1.4 			$	195.8 			$	1.3 			$	128.7 			$	1.2 			$	105.4 			$	50.0 		(a)	

(a)    Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
210

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:

 		Nine Months Ended September 30,	
		2020		2019	
Maximum Interest Rate		2.70 	%		3.43 	%	
Minimum Interest Rate		0.33 	%		1.83 	%	

The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table:

		Average Interest Rate for Funds		Average Interest Rate for Funds	
		Borrowed from the Utility Money Pool		Loaned to the Utility Money Pool	
		for Nine Months Ended September 30,		for Nine Months Ended September 30,	
Company		2020		2019		2020		2019	
AEP Texas		1.55 	%		2.71 	%		0.87 	%		— 	%	
AEPTCo		1.63 	%		2.72 	%		2.00 	%		2.57 	%	
APCo		2.14 	%		2.82 	%		0.99 	%		2.73 	%	
I&M		1.30 	%		2.56 	%		1.44 	%		2.73 	%	
OPCo		1.32 	%		2.80 	%		2.06 	%		2.68 	%	
PSO		1.24 	%		2.85 	%		1.95 	%		2.48 	%	
SWEPCo		1.55 	%		2.74 	%		— 	%		2.47 	%	

Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:

		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019	
 	 	Maximum	 	Minimum	 	Average		Maximum	 	Minimum	 	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	
	 	Loaned to	 	Loaned to	 	Loaned to		Loaned to	 	Loaned to	 	Loaned to	
	 	the Nonutility	 	the Nonutility	 	the Nonutility		the Nonutility	 	the Nonutility	 	the Nonutility	
Company	 	Money Pool	 	Money Pool	 	Money Pool		Money Pool	 	Money Pool	 	Money Pool	
AEP Texas	 	2.70 	%		0.33 	%		1.44 	%		3.02 	%		2.36 	%		2.70 	%	
SWEPCo	 	2.70 	%		0.33 	%		1.44 	%		3.02 	%		2.36 	%		2.70 	%	

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	
Nine Months	 	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds	
Ended	 	Borrowed		Borrowed		Loaned		Loaned		Borrowed		Loaned	
September 30,	 	from AEP	 	from AEP		to AEP	 	to AEP	 	from AEP	 	to AEP	
2020	 	2.70 	%		0.50 	%		2.70 	%		0.50 	%		1.45 	%		1.40 	%	
2019	 	3.02 	%		2.36 	%		3.02 	%		2.36 	%		2.70 	%		2.70 	%	

211

Short-term Debt (Applies to AEP, AEP Texas and SWEPCo)

Outstanding short-term debt was as follows:

		 		September 30, 2020		December 31, 2019	
				Outstanding		Interest		Outstanding		Interest	
Company		Type of Debt		Amount		Rate (a)		Amount		Rate (a)	
		 		(dollars in millions)	
AEP		Securitized Debt for Receivables (b)		$	703.0 			1.05 	%		$	710.0 			2.42 	%	
AEP		Commercial Paper		650.0 			0.21 	%		2,110.0 			2.10 	%	
AEP		364-Day Term Loan		1,000.0 			0.75 	%		— 			— 	%	
AEP Texas		COVID-19 Electricity Relief Program Loan (c)		2.0 			— 	%		— 			— 	%	
SWEPCo		Notes Payable		42.0 			2.46 	%		18.3 			3.29 	%	
		Total Short-term Debt		$	2,397.0 			 		$	2,838.3 			 	

(a)Weighted-average rate.
(b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
(c)Principal amount of loan shall not bear interest if paid in full by the maturity date. Unpaid principal after the maturity date will accrue interest of 2% per annum beginning the first day after the maturity date until all outstanding principal is paid.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.

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 September 30, 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, receivables would no longer be purchased by the bank conduits and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity.

Accounts receivable information for AEP Credit was as follows:
																											
		Three Months Ended 
September 30,		Nine Months Ended 
September 30,	
		2020		2019		2020		2019	
		(dollars in millions)	
Effective Interest Rates on Securitization of Accounts Receivable		0.36 	%		2.37 	%		1.05 	%		2.56 	%	
Net Uncollectible Accounts Receivable Written-Off		$	2.9 			$	8.8 			$	10.5 			$	19.8 		

		September 30, 2020		December 31, 2019	
		(in millions)	
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts		$	1,002.4 			$	841.8 		
Short-term – Securitized Debt of Receivables		703.0 			710.0 		
Delinquent Securitized Accounts Receivable		103.8 			39.6 		
Bad Debt Reserves Related to Securitization		52.7 			32.1 		
Unbilled Receivables Related to Securitization		227.4 			266.8 		

AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.
212

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.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were:

Company		September 30, 2020		December 31, 2019	
 		(in millions)	
APCo		$	117.3 			$	120.9 		
I&M		184.3 			141.8 		
OPCo		394.3 			330.3 		
PSO		122.0 			101.1 		
SWEPCo		177.6 			125.2 		

The fees paid to AEP Credit for customer accounts receivable sold were:

 		Three Months Ended September 30,		Nine Months Ended September 30,	
Company		2020		2019		2020		2019	
 		(in millions)	
APCo		$	2.0 			$	1.2 			$	5.0 			$	5.8 		
I&M		3.9 			2.4 			9.3 			8.4 		
OPCo		9.8 			6.4 			19.6 			22.1 		
PSO		1.5 			2.0 			3.8 			6.2 		
SWEPCo		2.8 			1.9 			6.8 			7.9 		

The proceeds on the sale of receivables to AEP Credit were:

 		Three Months Ended September 30,		Nine Months Ended September 30,	
Company		2020		2019		2020		2019	
		(in millions)	
APCo		$	323.5 			$	303.3 			$	961.8 			$	978.5 		
I&M		532.3 			485.3 			1,443.6 			1,378.9 		
OPCo		666.0 			602.6 			1,793.0 			1,746.1 		
PSO		369.2 			451.5 			961.4 			1,118.7 		
SWEPCo		478.3 			480.7 			1,225.3 			1,247.0 		

213

13. PROPERTY, PLANT AND EQUIPMENT

The disclosure in this note applies to AEP, AEP Texas, APCo, PSO and SWEPCo.

Asset Retirement Obligations

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. The Registrants recorded the following revisions to ARO estimates during the first nine months of 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 4 - Rate Matters for additional details. 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 4 - Rate Matters for additional details.
•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 6 - Acquisitions and Dispositions for additional details.
•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 5 - Commitments, Guarantees and Contingencies for additional details.

The following is a reconciliation of the aggregate carrying amounts of ARO for AEP, AEP Texas, APCo, PSO and SWEPCo:

Company		ARO as of December 31, 2019		Accretion
Expense		Liabilities
Incurred		Liabilities
Settled		Revisions in
Cash Flow
Estimates		ARO as of September 30, 2020	
		(in millions)	
AEP (a)(b)(c)(d)		$	2,418.9 			$	76.8 			$	0.2 			$	(155.4)			$	170.5 			$	2,511.0 		
AEP Texas (a)(d)		29.1 			0.7 			— 			— 			(16.8)			13.0 		
APCo (a)(d)		111.1 			5.9 			— 			(5.3)			195.4 			307.1 		
PSO (a)(d)		52.2 			2.3 			— 			(0.5)			(4.8)			49.2 		
SWEPCo (a)(c)(d)		212.2 			8.2 			— 			(5.6)			6.2 			221.0 		

(a)Includes ARO related to ash disposal facilities.
(b)Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.78 billion and $1.73 billion as of September 30, 2020 and December 31, 2019, respectively.
(c)Includes ARO related to Sabine and DHLC.
(d)Includes ARO related to asbestos removal.

214

14. REVENUE FROM CONTRACTS WITH CUSTOMERS

The disclosures in this note apply to all Registrants, unless indicated otherwise.

Disaggregated Revenues from Contracts with Customers

The tables below represent AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:

		Three Months Ended September 30, 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		$	1,053.3 			$	594.8 			$	— 			$	— 			$	— 			$	— 			$	1,648.1 		
Commercial Revenues		559.7 			259.2 			— 			— 			— 			— 			818.9 		
Industrial Revenues		504.5 			93.9 			— 			— 			— 			(0.1)			598.3 		
Other Retail Revenues		41.4 			10.0 			— 			— 			— 			— 			51.4 		
Total Retail Revenues		2,158.9 			957.9 			— 			— 			— 			(0.1)			3,116.7 		
															
Wholesale and Competitive Retail Revenues:															
Generation Revenues		158.4 			— 			— 			30.5 			— 			— 			188.9 		
	
Transmission Revenues (a)		84.4 			119.1 			317.7 			— 			— 			(276.9)			244.3 		
Renewable Generation Revenues (b)		— 			— 			— 			15.8 			— 			(0.3)			15.5 		
Retail, Trading and Marketing Revenues (c)		— 			— 			— 			447.5 			0.9 			(24.8)			423.6 		
Total Wholesale and Competitive Retail Revenues		242.8 			119.1 			317.7 			493.8 			0.9 			(302.0)			872.3 		
															
Other Revenues from Contracts with Customers (b)		34.1 			42.8 			2.4 			0.7 			33.9 			(43.7)			70.2 		

Total Revenues from Contracts with Customers		2,435.8 			1,119.8 			320.1 			494.5 			34.8 			(345.8)			4,059.2 		
															
Other Revenues:															
Alternative Revenues (b)		(1.0)			9.3 			(2.2)			— 			— 			6.6 			12.7 		
Other Revenues (b)		— 			36.2 			— 			(4.5)			(2.2)			(35.0)			(5.5)		
	
Total Other Revenues		(1.0)			45.5 			(2.2)			(4.5)			(2.2)			(28.4)			7.2 		
															
Total Revenues		$	2,434.8 			$	1,165.3 			$	317.9 			$	490.0 			$	32.6 			$	(374.2)			$	4,066.4 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $246 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 $19 million. The remaining affiliated amounts were immaterial.

215

																																													
		Three Months Ended September 30, 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		$	1,060.2 			$	588.0 			$	— 			$	— 			$	— 			$	— 			$	1,648.2 		
Commercial Revenues		612.5 			290.9 			— 			— 			— 			— 			903.4 		
Industrial Revenues		566.0 			99.3 			— 			— 			— 			1.5 			666.8 		
Other Retail Revenues		49.2 			10.6 			— 			— 			— 			— 			59.8 		
Total Retail Revenues		2,287.9 			988.8 			— 			— 			— 			1.5 			3,278.2 		
															
Wholesale and Competitive Retail Revenues:															
Generation Revenues (a)		231.3 			— 			— 			77.1 			— 			(34.2)			274.2 		
Transmission Revenues (b)		77.8 			110.9 			269.4 			— 			— 			(217.2)			240.9 		
Renewable Generation Revenues (c)		— 			— 			— 			20.1 			— 			— 			20.1 		
Retail, Trading and Marketing Revenues (c)		— 			— 			— 			395.3 			— 			0.5 			395.8 		
Total Wholesale and Competitive Retail Revenues		309.1 			110.9 			269.4 			492.5 			— 			(250.9)			931.0 		
															
Other Revenues from Contracts with Customers (c)		47.3 			42.9 			4.5 			14.8 			35.6 			(42.2)			102.9 		
															
Total Revenues from Contracts with Customers		2,644.3 			1,142.6 			273.9 			507.3 			35.6 			(291.6)			4,312.1 		
															
Other Revenues:															
Alternative Revenues (c)		1.2 			5.1 			(0.9)			— 			— 			(16.8)			(11.4)		
Other Revenues (c)		— 			38.9 			— 			26.4 			(11.2)			(39.8)			14.3 		
Total Other Revenues		1.2 			44.0 			(0.9)			26.4 			(11.2)			(56.6)			2.9 		
															
Total Revenues		$	2,645.5 			$	1,186.6 			$	273.0 			$	533.7 			$	24.4 			$	(348.2)			$	4,315.0 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $34 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $197 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues.

216

																																													
		Three Months Ended September 30, 2020	
		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	165.3 			$	— 			$	324.2 			$	222.6 			$	429.4 			$	195.8 			$	219.4 		
Commercial Revenues		78.0 			— 			138.4 			135.8 			181.2 			94.4 			135.0 		
Industrial Revenues		24.9 			— 			139.4 			139.7 			69.1 			55.0 			83.8 		
Other Retail Revenues		6.9 			— 			17.6 			1.6 			3.1 			18.4 			2.3 		
Total Retail Revenues		275.1 			— 			619.6 			499.7 			682.8 			363.6 			440.5 		
															
Wholesale Revenues:															
Generation Revenues (a)		— 			— 			70.3 			61.5 			— 			5.8 			42.3 		
	
Transmission Revenues (b)		101.8 			305.7 			30.8 			7.4 			17.2 			8.5 			28.7 		
	
Total Wholesale Revenues		101.8 			305.7 			101.1 			68.9 			17.2 			14.3 			71.0 		
															
Other Revenues from Contracts with Customers (c)		15.2 			3.0 			16.1 			17.7 			27.6 			4.8 			5.6 		

Total Revenues from Contracts with Customers		392.1 			308.7 			736.8 			586.3 			727.6 			382.7 			517.1 		
															
Other Revenues:															
Alternative Revenues (d)		(0.7)			(4.6)			(1.1)			0.4 			10.0 			(0.5)			0.2 		
Other Revenues (d)		40.6 			— 			— 			— 			3.4 			— 			— 		
	
Total Other Revenues		39.9 			(4.6)			(1.1)			0.4 			13.4 			(0.5)			0.2 		
															
Total Revenues		$	432.0 			$	304.1 			$	735.7 			$	586.7 			$	741.0 			$	382.2 			$	517.3 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $28 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 $243 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $15 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.

217

																																													
		Three Months Ended September 30, 2019	
		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	192.0 			$	— 			$	315.7 			$	198.2 			$	395.6 			$	231.9 			$	222.9 		
Commercial Revenues		110.6 			— 			147.2 			138.3 			180.5 			122.2 			144.3 		
Industrial Revenues		32.2 			— 			152.2 			138.7 			67.1 			84.1 			92.3 		
Other Retail Revenues		7.5 			— 			18.5 			1.9 			3.1 			24.9 			2.3 		
Total Retail Revenues		342.3 			— 			633.6 			477.1 			646.3 			463.1 			461.8 		
															
Wholesale Revenues:															
Generation Revenues (a)		— 			— 			70.4 			102.1 			— 			21.1 			50.7 		
Transmission Revenues (b)		97.7 			256.4 			26.2 			6.4 			13.7 			(3.4)			30.0 		
Total Wholesale Revenues		97.7 			256.4 			96.6 			108.5 			13.7 			17.7 			80.7 		
															
Other Revenues from Contracts with Customers (c)		8.2 			4.5 			18.7 			26.6 			41.0 			5.1 			7.0 		
															
Total Revenues from Contracts with Customers		448.2 			260.9 			748.9 			612.2 			701.0 			485.9 			549.5 		
															
Other Revenues:															
Alternative Revenues (d)		(0.7)			(1.2)			6.6 			(1.1)			12.4 			7.1 			(4.0)		
Other Revenues (d)		41.8 			— 			— 			— 			(2.8)			— 			— 		
Total Other Revenues		41.1 			(1.2)			6.6 			(1.1)			9.6 			7.1 			(4.0)		
															
Total Revenues		$	489.3 			$	259.7 			$	755.5 			$	611.1 			$	710.6 			$	493.0 			$	545.5 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $32 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 $194 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $20 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.

218

																																													
		Nine Months Ended September 30, 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		$	2,789.1 			$	1,610.6 			$	— 			$	— 			$	— 			$	— 			$	4,399.7 		
Commercial Revenues		1,523.6 			792.4 			— 			— 			— 			— 			2,316.0 		
Industrial Revenues		1,508.7 			290.4 			— 			— 			— 			(0.5)			1,798.6 		
Other Retail Revenues		118.2 			32.1 			— 			— 			— 			— 			150.3 		
Total Retail Revenues		5,939.6 			2,725.5 			— 			— 			— 			(0.5)			8,664.6 		
															
Wholesale and Competitive Retail Revenues:															
Generation Revenues		447.4 			— 			— 			106.1 			— 			— 			553.5 		
	
Transmission Revenues (a)		248.4 			341.6 			937.7 			— 			— 			(741.7)			786.0 		
	
Renewable Generation Revenues (b)		— 			— 			— 			50.7 			— 			(1.2)			49.5 		
Retail, Trading and Marketing Revenues (c)		— 			— 			— 			1,133.8 			(5.7)			(80.7)			1,047.4 		
Total Wholesale and Competitive Retail Revenues		695.8 			341.6 			937.7 			1,290.6 			(5.7)			(823.6)			2,436.4 		
															
Other Revenues from Contracts with Customers (b)		124.1 			112.3 			17.5 			1.7 			84.4 			(115.7)			224.3 		

Total Revenues from Contracts with Customers		6,759.5 			3,179.4 			955.2 			1,292.3 			78.7 			(939.8)			11,325.3 		
															
Other Revenues:															
Alternative Revenues (b)		(6.0)			49.2 			(77.4)			— 			— 			3.5 			(30.7)		
Other Revenues (b)		— 			78.1 			— 			13.2 			(6.7)			(71.3)			13.3 		
	
Total Other Revenues		(6.0)			127.3 			(77.4)			13.2 			(6.7)			(67.8)			(17.4)		
															
Total Revenues		$	6,753.5 			$	3,306.7 			$	877.8 			$	1,305.5 			$	72.0 			$	(1,007.6)			$	11,307.9 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $725 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 $81 million. The remaining affiliated amounts were immaterial.

219

																																													
		Nine Months Ended September 30, 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		$	2,797.6 			$	1,609.1 			$	— 			$	— 			$	— 			$	— 			$	4,406.7 		
Commercial Revenues		1,641.2 			889.4 			— 			— 			— 			— 			2,530.6 		
Industrial Revenues		1,647.3 			332.6 			— 			— 			— 			— 			1,979.9 		
Other Retail Revenues		136.1 			32.8 			— 			— 			— 			— 			168.9 		
Total Retail Revenues		6,222.2 			2,863.9 			— 			— 			— 			— 			9,086.1 		
															
Wholesale and Competitive Retail Revenues:															
Generation Revenues (a)		661.9 			— 			— 			282.0 			— 			(105.5)			838.4 		
Transmission Revenues (b)		215.4 			324.0 			814.3 			— 			— 			(603.6)			750.1 		
Renewable Generation Revenues (c)		— 			— 			— 			39.0 			— 			0.5 			39.5 		
Retail, Trading and Marketing Revenues (c)		— 			— 			— 			1,049.5 			— 			— 			1,049.5 		
Total Wholesale and Competitive Retail Revenues		877.3 			324.0 			814.3 			1,370.5 			— 			(708.6)			2,677.5 		
															
Other Revenues from Contracts with Customers (c)		128.8 			127.6 			12.6 			4.5 			80.4 			(113.6)			240.3 		
															
Total Revenues from Contracts with Customers		7,228.3 			3,315.5 			826.9 			1,375.0 			80.4 			(822.2)			12,003.9 		
															
Other Revenues:															
Alternative Revenues (c)		(55.7)			21.5 			(18.6)			— 			— 			(60.3)			(113.1)		
Other Revenues (c)		— 			117.3 			— 			53.2 			(6.7)			(109.2)			54.6 		
Total Other Revenues		(55.7)			138.8 			(18.6)			53.2 			(6.7)			(169.5)			(58.5)		
															
Total Revenues		$	7,172.6 			$	3,454.3 			$	808.3 			$	1,428.2 			$	73.7 			$	(991.7)			$	11,945.4 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $105 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $596 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues.
220

																																													
		Nine Months Ended September 30, 2020	
		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	447.8 			$	— 			$	954.4 			$	610.8 			$	1,162.6 			$	463.5 			$	498.7 		
Commercial Revenues		285.2 			— 			390.6 			376.0 			507.3 			247.8 			351.2 		
Industrial Revenues		91.4 			— 			415.0 			408.2 			199.1 			170.8 			245.9 		
Other Retail Revenues		22.3 			— 			50.9 			5.0 			9.8 			51.2 			6.6 		
Total Retail Revenues		846.7 			— 			1,810.9 			1,400.0 			1,878.8 			933.3 			1,102.4 		
															
Wholesale Revenues:															
Generation Revenues (a)		— 			— 			185.3 			215.5 			— 			9.9 			106.7 		
	
Transmission Revenues (b)		290.4 			902.6 			91.5 			22.1 			51.1 			20.2 			87.5 		
	
Total Wholesale Revenues		290.4 			902.6 			276.8 			237.6 			51.1 			30.1 			194.2 		
															
Other Revenues from Contracts with Customers (c)		33.4 			17.5 			46.8 			60.6 			78.9 			23.2 			21.1 		

Total Revenues from Contracts with Customers		1,170.5 			920.1 			2,134.5 			1,698.2 			2,008.8 			986.6 			1,317.7 		
															
Other Revenues:															
Alternative Revenues (d)		(0.3)			(82.3)			(11.9)			5.4 			49.6 			1.5 			0.5 		
Other Revenues (d)		86.9 			— 			— 			— 			13.3 			— 			— 		
	
Total Other Revenues		86.6 			(82.3)			(11.9)			5.4 			62.9 			1.5 			0.5 		
															
Total Revenues		$	1,257.1 			$	837.8 			$	2,122.6 			$	1,703.6 			$	2,071.7 			$	988.1 			$	1,318.2 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $85 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 $715 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $49 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.

221

																																													
		Nine Months Ended September 30, 2019	
		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	454.9 			$	— 			$	944.7 			$	558.8 			$	1,155.5 			$	519.6 			$	503.7 		
Commercial Revenues		314.5 			— 			421.5 			371.4 			573.7 			304.3 			371.1 		
Industrial Revenues		98.8 			— 			444.3 			411.9 			233.9 			238.1 			257.2 		
Other Retail Revenues		22.7 			— 			56.5 			5.4 			9.8 			63.1 			6.7 		
Total Retail Revenues		890.9 			— 			1,867.0 			1,347.5 			1,972.9 			1,125.1 			1,138.7 		
															
Wholesale Revenues:															
Generation Revenues (a)		— 			— 			200.1 			327.4 			— 			35.5 			152.7 		
Transmission Revenues (b)		282.0 			775.3 			77.6 			18.8 			42.0 			21.9 			78.0 		
Total Wholesale Revenues		282.0 			775.3 			277.7 			346.2 			42.0 			57.4 			230.7 		
															
Other Revenues from Contracts with Customers (c)		22.9 			12.6 			48.2 			76.2 			113.3 			16.7 			20.1 		
															
Total Revenues from Contracts with Customers		1,195.8 			787.9 			2,192.9 			1,769.9 			2,128.2 			1,199.2 			1,389.5 		
															
Other Revenues:															
Alternative Revenues (d)		(0.4)			(17.8)			11.2 			(1.4)			22.0 			(25.3)			(47.4)		
Other Revenues (d)		122.6 			— 			— 			— 			3.8 			— 			— 		
Total Other Revenues		122.2 			(17.8)			11.2 			(1.4)			25.8 			(25.3)			(47.4)		
															
Total Revenues		$	1,318.0 			$	770.1 			$	2,204.1 			$	1,768.5 			$	2,154.0 			$	1,173.9 			$	1,342.1 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $96 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 $587 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.

222

Fixed Performance Obligations

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of September 30, 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		2020		2021-2022		2023-2024		After 2024		Total	
		(in millions)	
AEP		$	263.8 			$	188.3 			$	164.2 			$	223.4 			$	839.7 		
AEP Texas		108.2 			— 			— 			— 			108.2 		
AEPTCo		274.8 			— 			— 			— 			274.8 		
APCo		40.1 			33.1 			26.6 			11.6 			111.4 		
I&M		8.6 			10.9 			8.8 			4.5 			32.8 		
OPCo		16.5 			5.3 			— 			— 			21.8 		
PSO		3.8 			— 			— 			— 			3.8 		
SWEPCo		10.3 			— 			— 			— 			10.3 		

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 material contract assets as of September 30, 2020 and December 31, 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 material contract liabilities as of September 30, 2020 and December 31, 2019.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrant Subsidiaries’ 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 September 30, 2020 and December 31, 2019. See “Securitized Accounts Receivable - AEP Credit” section of Note 12 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:

Company		September 30, 2020		December 31, 2019	
		(in millions)	
AEPTCo		$	79.9 			$	65.9 		
APCo		49.3 			47.3 		
I&M		30.5 			37.1 		
OPCo		36.5 			33.9 		
PSO		11.0 			9.7 		
SWEPCo		18.4 			17.6 		

223

CONTROLS AND PROCEDURES

During the third quarter of 2020, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants 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 SEC’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 the Registrants’ 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 September 30, 2020, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.

There was no change 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 third quarter of 2020 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
224

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 5 incorporated herein by reference.

Item 1A.  Risk Factors

The AEP 2019 Annual Report on Form 10-K includes a detailed discussion of risk factors. As of September 30, 2020, the risk factors appearing in AEP’s 2019 Annual Report are supplemented and updated as follows:

AEP’s Financial Condition and Results of Operations could continue to be Adversely Affected by the Ongoing Coronavirus Pandemic

AEP is responding to the global 2019 novel coronavirus (COVID-19) pandemic by taking steps to mitigate the potential risks posed by its spread. 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 continue to disrupt economic activity in AEP’s service territory and could reduce future demand for energy, particularly from commercial and industrial customers. AEP provides a critical service to its customers which means that it must keep its employees who operate its businesses safe and minimize unnecessary risk of exposure to the virus. AEP has updated and implemented a company-wide pandemic plan to address specific aspects of the coronavirus pandemic. This plan guides AEP’s emergency response, business continuity, and the precautionary measures that AEP is taking on behalf its employees and the public. AEP has taken extra precautions for its employees who work in the field and for employees who continue to work in its facilities, and AEP has implemented work from home policies where appropriate.

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. These conditions might also impact the Registrants’ access to and cost of capital. This is a rapidly evolving situation that could lead to extended disruption of economic activity in AEP’s markets.

AEP has instituted measures to ensure its supply chain remains open; however, there could be global shortages that will impact AEP’s maintenance and capital programs that AEP currently cannot anticipate. AEP will continue to monitor developments affecting both its workforce and its customers, and will take additional precautions that are determined to be necessary in order to mitigate the impacts.

AEP continues to implement strong physical and cyber security measures to ensure that its systems remain functional in order to both serve its operational needs with a remote workforce and keep them running to ensure uninterrupted service to customers.

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. 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.

AEP will continue to review and modify its plans as conditions change. Despite AEP’s efforts to manage these impacts, their ultimate impact also depends on factors beyond AEP’s knowledge or control, including the duration and severity of this outbreak, its impact on economic and market conditions, as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, AEP currently cannot estimate the potential impact to its financial position, results of operations and cash flows.

225

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. Among other provisions, HB 6 phased out current energy efficiency including lost shared savings revenues of $26 million annually and renewable mandates no later than 2020 and after 2026, respectively. 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 coal-fired unit costs through 2030. AEP and OPCo engaged in lobbying efforts and provided testimony during the legislative process in support of HB 6. 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 an alleged 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. To the extent that OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030 or fully recover energy efficiency costs through 2020, 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 and their potential involvement with various current or future litigation arising out HB 6.

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

AEP and several nonaffiliated utility companies 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 September 30, 2020, OVEC has outstanding indebtedness of approximately $1.3 billion, of which APCo, I&M, and OPCo are collectively responsible for $563 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.

Energy Harbor (formerly FirstEnergy Solutions), a nonaffiliated party, whose aggregate power participation ratio is 4.85% under the ICPA, filed a petition seeking protection under the bankruptcy law. In May 2020, Energy Harbor entered into a bankruptcy settlement and resumed performance under the ICPA as of June 1, 2020. In July 2020, federal prosecutors arrested the Speaker of the Ohio House of Representatives and four other individuals alleging that they engaged in a bribery and money laundering scheme connected to the passage of HB 6. Subsequently, proposed legislation was introduced that would repeal HB 6. 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 proposed legislation and will continue to monitor the 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%.

226

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 3.  Defaults Upon Senior Securities

None

Item 4.  Mine Safety Disclosures

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 September 30, 2020.

Item 5.  Other Information

On October 21, 2020, the Company entered into a separation, release of all claims and noncompetition agreement with Ms. Hillebrand pursuant to which the Company will provide $1,106,875 in severance benefits due to the elimination of her position and separation from service, effective December 31, 2020. This amount is equivalent to 1× her annual base salary and target annual incentive award, which is the current severance benefit for all participants under AEP’s Executive Severance plan. Half of this amount will be paid 6 months after her termination date and the remainder will be paid over the following 13 biweekly pay periods. In addition, the Company agreed to provide $500,000 in unrestricted AEP shares under AEP’s Long-Term Incentive Plan upon her separation from AEP service. The number of unrestricted AEP shares provided to Ms. Hillebrand will be determined by dividing the $500,000 value by the closing price of AEP Common Stock as reported by NASDAQ on December 31, 2020 and will be granted under AEP’s Long-Term Incentive Plan. This agreement also contains among other provisions, a one-year non-competition agreement and affirms certain non-solicitation, confidentiality and cooperation stipulations.

227

Item 6.  Exhibits

The documents designated with an (*) below 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.

Exhibit	 	Description	 	Previously Filed as Exhibit to:	
 	 	 	
AEP‡ File No. 1-3525			
			
4.1		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		Form 8-K dated August 14, 2020 Exhibit 4.1	
4.2		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, Exhibits 4(c) and 4(d); Form 8-K, Exhibit 4.3, dated March 19, 2019	
4.3		Supplemental Indenture No. 2, dated August 14, 2020, from the Company to The Bank of New York Mellon Trust Company, N.A., as trustee		Form 8-K dated August 14, 2020 Exhibit 4.3	

	

	

	

	

	
	
SWEPCo‡   File No. 1-3146			
					
4.4		Amendment to Certificate of Incorporation filed with Delaware Secretary of State effective August 31, 2020 to authorize a reverse stock split of the common stock, eliminate the authorized preferred stock and reduce the authorized number of shares of common stock		Form 8-K dated September 1, 2020 Exhibit 3.1	

The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.

Exhibit		Description		AEP		AEP
Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
10.1		AEP System Stock Ownership Requirement Plan As Amended and Restated Effective October 1, 2020		X															
10.2		AEP Retainer Deferral Plan For Non-Employee Directors As Amended and Restated Effective October 1, 2020		X															
10.3		AEP Stock Unit Accumulation Plan For Non-Employee Directors As Amended Effective October 1, 2020		X															
10.4		Severance, Stock Award, Release of All Claims and Noncompetition Agreement dated October 21, 2020 between AEPSC and Lana Hillebrand		X															
31(a)		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002		X		X		X		X		X		X		X		X	
31(b)		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002		X		X		X		X		X		X		X		X	
32(a)		Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code		X		X		X		X		X		X		X		X	
32(b)		Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code		X		X		X		X		X		X		X		X	
95		Mine Safety Disclosures																X	
228

																																																									
Exhibit		Description		AEP		AEP
Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
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		X		X		X		X		X		X		X		X	
101.CAL		XBRL Taxonomy Extension Calculation Linkbase		X		X		X		X		X		X		X		X	
101.DEF		XBRL Taxonomy Extension Definition Linkbase		X		X		X		X		X		X		X		X	
101.LAB		XBRL Taxonomy Extension Label Linkbase		X		X		X		X		X		X		X		X	
101.PRE		XBRL Taxonomy Extension Presentation Linkbase		X		X		X		X		X		X		X		X	
104		Cover Page Interactive Data File		Formatted as Inline XBRL and contained in Exhibit 101.	
229

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

AMERICAN ELECTRIC POWER COMPANY, INC.

By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer

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

By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer

Date:  October 22, 2020
230

Exhibit 10.1

AMERICAN ELECTRIC POWER SYSTEM
STOCK OWNERSHIP REQUIREMENT PLAN

(As Amended and Restated Effective October 1, 2020)

ARTICLE I

PURPOSE AND EFFECTIVE DATE

1.1 The Human Resources Committee (“HRC”) of the Board of Directors of American Electric Power Company, Inc. believes that it is critical to AEP’s long-term success to effectively align the long-term financial interests of senior executives with those of AEP’s shareholders and that an effective alignment is best accomplished by substantial, long-term stock ownership. The American Electric Power System Stock Ownership Requirement Plan (the “Plan”) was established by American Electric Power Service Corporation (the “Company”) and such subsidiaries of the Parent Corporation that have Eligible Employees to facilitate the achievement and maintenance of Minimum Stock Ownership Requirements assigned to Eligible Employees.

1.2 Except as otherwise specified herein, the effective date of this Amended and Restated American Electric Power System Stock Ownership Requirement Plan is October 1, 2020. This document amends and restates the Plan as most recently amended and restated by a document that was executed on June 20, 2017.

ARTICLE II

DEFINITIONS

2.1 “Account” means the separate memo account established and maintained by the Committee (or the record keeper employed by the Company) to record the number of Shares and Share Equivalents that have been designated in accordance with the terms of this Plan to satisfy all Minimum Stock Ownership Requirements assigned to a Participant.

2.2 “AEP” means the Parent Corporation and its direct and indirect subsidiaries.

2.3 “Applicable Tax Payments” means the following types of taxes that AEP may withhold and pay that are described as follows:

(a) Federal Insurance Contributions Act (FICA) tax imposed under Code Sections 3101, 3121(a) and 3121(v)(2) that apply to an amount deferred under the Plan before the amount is paid or made available to the Participant (the “FICA Amount”);

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(b) State, local, or foreign tax obligations arising from participation in the Plan that apply to an amount deferred under the Plan before the amount is paid or made available to the Participant (the “State, Local, or Foreign Tax Amount”);

(c) Income tax at source on wages imposed under Code Section 3401 or the corresponding withholding provisions of applicable state, local and foreign tax laws as a result of the payment of the FICA Amount or the State, Local, or Foreign Tax Amount; and

(d) The additional income tax at source on wages attributable to pyramiding Code Section 3401 wages and taxes;

provided, however, that the total Applicable Tax Payments may not exceed such limits as may be applicable to comply with the requirements of Code Section 409A.

2.4 “Career Share Account” means a separate memo account that is a subset of the Account that is maintained to identify the Career Share Units used to satisfy a Participant’s Minimum Stock Ownership Requirements.

2.5 “Career Share Unit” or “Career Share” means a type of Share Equivalent that is tracked in a Participant’s Career Share Account in order to determine whether and when the Participant has satisfied his or her Minimum Stock Ownership Requirements. Career Shares also have been generically referred to as “Phantom Stock Units” in Company communications.

2.6 “Claims Reviewer” means the person or committee designated by the Company (or by a duly authorized person) as responsible for the review of claims for benefits under the Plan in accordance with Section 8.1. Until changed, the Claims Reviewer shall be the Company’s employee who is the head of the Executive Benefits area of the Human Resources department.

2.7 “Code” means the Internal Revenue Code of 1986 as amended from time to time.

2.8 “Committee” means the committee designated by the Company (or by a duly authorized person) as responsible for the administration of the Plan. Until changed, the Committee shall consist of the employees of the Company holding the following positions: chief executive officer of the Company; head of the Human Resources department (currently, Vice President Human Resources); the employee to whom the head of the Human Resources department reports (currently, Senior Vice President & Chief Administrative Officer) and the chief financial officer of the Company. The Committee may authorize any person or persons to act on its behalf with full authority in regard to any of its duties and hereunder other than those set forth in Section 9.2.

2.9 “Common Stock” means the common stock, $6.50 par value, of the Parent Corporation.

2

2.10 “Company” means American Electric Power Service Corporation.

2.11 “Eligible Employee” means any employee of AEP who is hired into or promoted to a position that is eligible to be assigned a Minimum Stock Ownership Requirement, and only so long as a Minimum Stock Ownership Requirement applies. At the date of execution of this document, a Minimum Stock Ownership Requirement is assigned to those employees employed at exempt salary grade 36 or higher. An individual who is not directly compensated by AEP or who is not treated by AEP as an active employee shall not be considered an Eligible Employee.

2.12 First Date Available” or “FDA” means the last day of the month coincident with or next following the date that is six (6) months after the date of the Participant’s or Former Participant’s Termination.

2.13 “Incentive Compensation Deferral Plan” means the American Electric Power System Incentive Compensation Deferral Plan, as amended from time to time.

2.14 “Long Term Incentive Plan” or “LTIP” means the American Electric Power System Long-Term Incentive Plan, as amended from time to time, including any successor plan or plans. The LTIP that is in effect as of the date this restated Plan is executed is entitled the “Amended and Restated American Electric Power System Long-Term Incentive Plan – Approved by Shareholders April 17, 2010 (as amended through September 25, 2012).”

2.15 “Key Employee” means a Participant who is classified as a “specified employee” at the time of Termination in accordance with the policies adopted by the Committee in order to comply with the requirements of Section 409A(a)(2)(B)(i) of the Code and the guidance issued thereunder.

2.16 “Market Value” means the closing price of a Share, as reported on the NASDAQ Stock Market LLC on the date in question or, if the Share shall not have been traded on such date or if the NASDAQ Stock Market LLC is closed on such date, then the first day prior thereto on which the Common Stock was so traded.

2.17 “Minimum Stock Ownership Requirement” or “MSOR” means the targeted aggregate number of Shares and Share Equivalents specified under the terms of this Plan as applicable to the Participant. Participants may be assigned multiple minimum stock ownership requirements. Any MSOR assigned to a Participant shall no longer be applicable to such Participant after the date of the Participant’s Termination.

2.18 “MSOR Window Period” means the period that begins as of the date a particular MSOR is effective with respect to an Eligible Employee (or Participant, with regard to any increase in his or her MSOR) and ends on the five (5) year anniversary of that date.

3

2.19 “Next Date Available” or “NDA” means the June 30 of the calendar year immediately following the calendar year in which falls the Participant’s Termination.

2.20 “Parent Corporation” means American Electric Power Company, Inc., a New York corporation, and any successor thereto.

2.21 “Participant” is defined in Article IV.

2.22 “Performance-Based Compensation” has the meaning set forth in Section 409A(a)(4)(B)(iii) of the Code.

2.23 “Performance Shares” means performance shares or performance share units (or other similar types of equity incentive compensation) awarded under the American Electric Power System Performance Share Incentive Plan or the Long-Term Incentive Plan. Reference in this Plan to the “12/10/2003 Performance Share Awards” shall be deemed to refer to the Performance Shares that were issued with a grant date of December 10, 2003 and subject to a performance period from December 10, 2003 through December 31, 2004.

2.24 “Phantom Stock Units” means an award under the Long-term Incentive Plan to a Participant of a number of hypothetical share units with respect to shares of Common Stock. See, for example, the definitions of “Career Share Unit,” above, and “Restricted Stock Unit,” below.

2.25 “Plan Year” means the twelve-month period commencing each January 1 and ending the following December 31.

2.26 “Restricted Stock Unit” means a type of Phantom Stock Unit issued under the Long-Term Incentive Plan pursuant to a Restricted Stock Unit Award Agreement.

2.27 “Share” means a share of common stock of the Parent Corporation, and includes, but is not limited to, such shares as may be purchased directly by or for the Participant or through the American Electric Power Company, Inc. Dividend Reinvestment and Direct Stock Purchase Plan or issued in connection with the Participant’s performance of services for AEP, such as pursuant to the American Electric Power System Long-Term Incentive Plan.

2.28 “Share Equivalent” is determined by reference to (1) the amount credited to the Participant’s Career Share Account under this Plan and (2) to the extent eligible for designation in accordance with Section 5.2, (A) the Participant’s outstanding Restricted Stock Units and (B) the Participant’s AEP Stock Fund accounts maintained in connection with the American Electric Power System Retirement Savings Plan, the American Electric Power System Supplemental Retirement Savings Plan, and the American Electric Power System Incentive Compensation Deferral Plan. No certificates shall have been issued with respect to such Share Equivalents.

4

(a) To the extent that the amount credited under these arrangements are not otherwise reported under the terms of the applicable plan as a number of shares of Common Stock, the number of Share Equivalents attributable to such amount shall be determined by dividing the dollar amount so credited by the Market Value of a Share determined as of the applicable valuation date; provided that effective beginning May 1, 2008, the number of Share Equivalents attributable to such amount shall be determined by

(i)    multiplying the dollar amount credited to such AEP Stock Fund under the Plan by the Dilution Percentage with respect to that fund as of the applicable valuation date; then

(ii)    dividing the product in (i) by the Market Value of a Share determined as of the applicable valuation date.

(b)    For purposes of this Section, the “Dilution Percentage” applicable to a plan’s AEP Stock Fund shall be determined by

(i)    dividing the aggregate Market Value of the Shares held by the fund (or, with respect to the phantom AEP Stock Fund that is maintained with respect to the American Electric Power System Supplemental Retirement Savings Plan and the American Electric Power System Incentive Compensation Deferral Plan, by the actual fund to which such phantom fund is tied – currently, the AEP Stock Fund under the American Electric Power System Retirement Savings Plan); by

(ii)    the value of all of the assets held in that fund (or such fund to which a phantom fund is tied) as of the applicable valuation date.

2.29 “Termination” means termination of employment with the Company and its subsidiaries and affiliates for any reason; provided that effective with respect to Participants whose employment terminates on or after January 1, 2005, determinations as to the circumstances that will be considered a Termination (including a disability and leave of absence) shall be made in a manner consistent with the written policies adopted by the HRC from time to time to the extent such policies are consistent with the requirements imposed under Code 409A(a)(2)(A)(i).

2.30 “Vested” or “Earned and Vested” means, for purposes of this Plan, that the Shares or Share Equivalents credited to the Participant have become both objectively determinable and no longer subject to a substantial risk of forfeiture.

2.31 “2006 Distribution Election Period” means the period or periods designated by the Committee during which Participants (or Former Participants) are given the opportunity to select among the distribution options set forth in Article VII, provided that any such period shall end no later than December 31, 2006.

5

ARTICLE III

ADMINISTRATION

3.1 The Plan shall be administered by the Committee. The Committee shall have full discretionary power and authority (i) to administer and interpret the terms and conditions of the Plan and (ii) to establish reasonable procedures with which Participants, Former Participant and beneficiaries must comply to exercise any right or privilege established hereunder. The rights and duties of the Participants and all other persons and entities claiming an interest under the Plan shall be subject to, and bound by, actions taken by or in connection with the exercise of the powers and authority granted under this Article.

3.2 The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.

3.3 The Company shall maintain, or cause to be maintained, records showing the individual balances in each Participant’s Account, including each Participant’s Career Share Account. Statements setting forth the value of the amount credited to the Participant's Account shall be made available to each Participant no less often than once per year. The maintenance of the Account records and the distribution of statements may be delegated to a record keeper by either the Company or the Committee.

ARTICLE IV

PARTICIPATION

An Eligible Employee shall become a Participant as of the date that the Eligible Employee is first assigned a Minimum Stock Ownership Requirement.

ARTICLE V

SATISFACTION OF MINIMUM STOCK OWNERSHIP REQUIREMENT

5.1 Accounts. The Committee shall establish and maintain an Account for each Participant that will record the number of Shares and Share Equivalents that have been designated in accordance with the terms of this Plan to satisfy the Minimum Stock Ownership Requirement applicable to such Participant.

5.2 Share Commitment Designated by Participant.

6

(a) A Participant may from time to time designate that certain Shares or Share Equivalents that are owned solely by the Participant or otherwise credited solely to the Participant be credited to the Account of such Participant. A Participant shall be permitted to so designate any Shares or Share Equivalents only to the extent the following requirements have been satisfied:

(i)The Shares or Share Equivalents have been awarded to the Participant, whether or not such Shares or Share Equivalents are then Vested;

(ii)The Shares or Share Equivalents are not of a type that may be eligible for automatic allocation to the Participant’s Career Share Account pursuant to Section 5.3, below;

(iii)The Shares or Share Equivalents are not encumbered, pledged or hypothecated in favor of a third party (other than the Participant or AEP) in any way; and

(iv)If Shares, such Shares are held in an account which the Committee determines in its sole discretion provides it with the ability to confirm the number of Shares and the interest of the Participant therein.

(b)    A Restricted Stock Unit may be considered designated by a Participant for purposes of this section only at such time or times and only to the extent that, by the terms of its Restricted Stock Unit Award Agreement, payment of such award would be made in shares of unrestricted Common Stock at such time if the Participant were then fully vested. For example, certain such awards currently specify that payment upon vesting would be made in cash to a Participant who is a Section 16 Officer at that time. Even if the Participant had been permitted to sign a document that “designated” such Restricted Stock Units, such awards would not be considered designated for purposes of this Plan as of any date that the Company considers such Participant a Section 16 Officer.

(c)    Any designation made by a Participant under this Section shall be made in writing and in a form that is satisfactory to the Committee.

5.3 Accrual of Career Shares.

(a)    Determination Date. For purposes of this Section 5.3, the term “Determination Date” means

(i)    the date that is six months prior to the end of the performance period, with respect to an award of Performance Shares that qualifies as Performance-Based Compensation and that is based on services performed over a period of at least 12 months; or

7

(ii)    to the extent that the awarded Performance Shares are not Performance-Based Compensation that is based on services performed over a period of at least 12 months, the latest of (A) the December 31 immediately prior to the year in which the services on which the Performance Shares is based are to be performed, (B) the date the Participant first became an Eligible Employee, or (C) the date the Performance Shares are granted to the Participant.

(b)    Participant Has Not Satisfied MSOR.

(i)    If a Participant has not satisfied all applicable Minimum Stock Ownership Requirements on or before a Determination Date applicable to Performance Shares that have been awarded to such Participant, the Participant’s Career Share Account shall be credited with the number of Shares or Share Equivalents that become Earned and Vested (reduced, however, to the extent the amount deferred would otherwise exceed an amount that allows for the current payment of Applicable Tax Payments) for the Participant as a result of the award of such Performance Shares. Notwithstanding the foregoing provisions of this paragraph (i), effective for Determination Dates occurring on or after May 1, 2008, the number of Shares or Share Equivalents so credited to the Participant’s Career Share Account shall be limited to that number needed to satisfy the Participant’s MSOR, and the balance, if any, of such Earned and Vested Performance Shares shall be administered without regard to the provisions of this Plan. For this purpose, the number of Shares or Share Equivalents needed to satisfy the Participant’s MSOR shall be determined by reference to the highest MSOR that is applicable to such Participant as of the Determination Date with respect to such Performance Shares:

(A)    after taking into account

(1)    Shares or Share Equivalents that are credited to the Participant’s Account as of such Determination Date pursuant to the Participant’s designation under Section 5.2 no later than such Determination Date;

(2)    the Share Equivalents that are credited to the Participant’s Career Share Account as of such Determination Date; and

(3)    the Share Equivalents attributable to reinvested dividends through the date such Performance Shares become Earned and Vested, but only to the extent such reinvested dividends are attributable to the Share Equivalents that were credited to the Participant’s Career Share Account as of such Determination Date; but

8

(B)    Disregarding the Share Equivalents that may be credited to such Participant’s Career Share Account pursuant to this subsection 5.3(b)(i), that either

(1)    have a Determination Date that is after the Determination Date for such Performance Shares; or

(2)    have not become Earned and Vested as of the date such Performance Shares become Earned and Vested.

(ii)    The Share Equivalents that are disregarded pursuant to subparagraph 5.3(b)(i)(B) may include those attributable to Performance Shares that had become Earned and Vested and thereupon credited to such Participant’s Career Share Account, and as a result, such Career Share Account may be credited with Share Equivalents in excess of the number actually needed to satisfy the highest MSOR that is applicable to such Participant as of the applicable Determination Date.

(iii)    If the same Determination Date applies to more than one award of Performance Shares for a particular Participant, and such awards also become Earned and Vested as of the same date, the following priority shall be used in determining which award (or portion thereof) shall be credited to the Participant’s Career Share Account: (A) Share Equivalents shall be credited in the same order in which they were initially granted, and (B) if they were granted as of the same date, Share Equivalents shall be credited first from Performance Shares relating to a performance period that began the earliest.

(iv)    A Participant’s Career Share Account shall be credited to the extent otherwise described in this Section 5.3(b) even if the Participant shall have satisfied all applicable MSOR or shall have ceased to remain an Eligible Employee during the period between the Determination Date and the date the Performance Shares are Earned and Vested. However, if a Participant shall have no MSOR as of an applicable Determination Date by reason of the Participant’s having ceased to remain an Eligible Employee, the payment or deferral of the amounts that become payable to the Participant as a result of an award of Performance Shares to which such Determination Date applies shall be determined in accordance with other plans and programs as may apply, including, for example, the Incentive Compensation Deferral Plan.

(c)    Participant Has Satisfied MSOR. If a Participant has satisfied his or her MSOR on or before the applicable Determination Date, the payment or deferral of the amounts that become payable to the Participant as a result of an award of Performance Shares shall be determined in accordance with other plans and programs as may apply, including, for example, the Incentive Compensation Deferral Plan.

9

ARTICLE VI

CAREER SHARE ACCOUNT
DIVIDENDS AND ADJUSTMENTS

6.1 Reinvestment of Dividends. Effective on each dividend payment date with respect to the Common Stock, the Career Share Account of a Participant shall be credited with an additional number of whole and fractional Share Equivalents, computed to three decimal places, equal to the product of the dividend per share then payable, multiplied by the number of Share Equivalents then credited to such Career Share Account, divided by the Market Value on the dividend payment date.

6.2 Adjustments. The number of Share Equivalents credited to a Participant’s Career Share Account shall be appropriately adjusted for any change in the Common Stock by reason of any merger, reclassification, consolidation, recapitalization, stock dividend, stock split or any similar change affecting the Common Stock.

ARTICLE VII

CAREER SHARE ACCOUNT
DISTRIBUTIONS

7.1 Upon a Participant’s Termination for any reason, the Company shall cause the amount credited to the Participant’s Career Share Account the Participant to be paid in accordance with the following rules:

(a)    Medium of Payment. Effective for all payments made on or after July 1, 2017, payments for whole Career Shares shall be made in shares of Common Stock and payments for any fraction of a Career Share shall be made in cash or applied as additional participant tax withholding at the Company’s option. All payments to Participants made prior to July 1, 2017 , shall be made in cash.

(i)When making payment in the form of Shares of Common Stock, each whole Career Share (including any attributable to Share Equivalents credited to the Participant’s Career Share Account) that becomes payable shall be converted into a single Share of Common Stock for delivery in accordance with Section 7.1 (b) (6)_(Delivery of Shares of Common Stock).

(ii)Cash payments of Career Shares (including fractional Career Shares paid on or after July 1, 2017) shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days prior to the applicable distribution date (i.e., the Participant’s date of
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Termination, deferred distribution date, respective installment payment dates or the date of the Participant’s death, as the case may be).

(b)    Timing and Form of Distribution. Except as otherwise provided in Section 7.2, the following rules shall apply with regard to the timing and form of the distributions to be made from the Participant’s Career Share Account:

(1)    Form of Distribution. The Company shall cause the Participant to be paid the full amount credited to his or her Active Career Share Account in accordance with his or her effective election in one of the following forms:

(A) A single lump sum distribution

(i) as of the First Date Available; or

(ii) as of the Next Date Available; or

(iii) as of the fifth anniversary of the First Date Available; or

(iv) as of the fifth anniversary of the Next Date Available; or

(B) In five (5) annual installments commencing

(i) as of the First Date Available; or

(ii) as of the Next Date Available; or

(iii) as of the fifth anniversary of the First Date Available; or

(iv) as of the fifth anniversary of the Next Date Available; or

(C) In ten (10) annual installments commencing.

(i) as of the First Date Available; or

(ii) as of the Next Date Available.

(2)    Effective Election. For this purpose, a Participant’s election with respect to the distribution of his or her Career Share Account shall not be effective unless all of the following requirements are satisfied.

(A)    The election is submitted to the Company in writing in a form determined by the Committee to be acceptable;

(B)    The election is submitted timely. For purposes of this paragraph, a distribution election will be considered “timely” only if it is
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submitted prior to the Participant’s Termination and it satisfies the requirements of (i), (ii) or (iii), below, as may be applicable:

(i)    Submitted no later than the first Determination Date after June 30, 2006 with respect to a Participant who had neither a 12/10/2003 Performance Share Award nor any amount credited to his Career Share Account as of June 30, 2006; or

(ii)    Submitted during a 2006 Distribution Election Period that is applicable to the Participant, but only with regard to the distribution election form last submitted by such Participant before the expiration of that period; or

(iii)    If the Participant is submitting the election to change the timing or form of distribution that is then in effect with respect to the Participant’s Career Share Account other than an effective distribution election submitted as part of the 2006 Distribution Election Period, such election must be submitted at least one year prior to the date of the Participant’s Termination.

(C)    If the Participant is submitting the election pursuant to paragraph (b)(2)(B)(iii) to change the timing or form of distribution that is then in effect with respect to the Participant’s Career Share Account (i.e., the Participant is not submitting an election with his initial applicable Determination Date [(B)(i)] nor during the applicable 2006 Distribution Election Period [(B)(ii)], the newly selected option must result in the further deferral of the first scheduled payment by at least 5 years. For purposes of compliance with the rule set forth in Section 409A(a) of the Code (and the regulations issued thereunder), each distribution option described in Section 7.1(b)(1) shall be treated as a single payment as of the first scheduled payment date.

(D)    If the Participant is submitting the election pursuant to paragraph (b)(2)(B)(ii) to change the timing or form of distribution that is then in effect with respect to the Participant’s Career Share Account, the newly selected option may not defer payments that the Participant would have received in 2006 if not for the new distribution election nor cause payments to be made in 2006 if not for the new distribution election.

(3)    For purposes of this Section 7.1(b), if a Participant’s effective distribution election form was submitted using the options that had been made available under the Plan as in effect prior to January 1, 2005 [i.e., as either
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(A) a single lump-sum payment, or in annual installment payments over not less than two nor more than ten years; (B) commencing within 60 days after the date of the Participant’s Termination or the first, second, third, fourth or fifth anniversary of the Participant’s Termination], then:

(A)    If the Participant’s Termination occurs prior to the expiration of the 2006 Distribution Election Period last applicable to the Participant, the Participant’s effective distribution election form shall be given full effect. Solely for purposes of this paragraph (3)(A), a participant’s distribution election form shall be considered effective notwithstanding the requirement of Section 7.1(b)(2)(B)(iii) (which requires that a form be submitted at least one year prior to the date of the Participant’s Termination), provided that such form had become effective prior to the Participant’s Termination in accordance with the terms applicable to such election form at the time it was submitted by the Participant; and

(B)    If the Participant’s Termination occurs after the expiration of the last applicable 2006 Distribution Election Period, the Participant shall be considered to have elected the corresponding option as set forth in Schedule A attached to this Plan.

(4)    If the provisions of Section 7.1(b)(3) are not applicable to a Participant and the Participant fails to submit an effective distribution election with regard to his Career Share Account that satisfies the requirements of Section 7.1(b)(2)(B)(i) (by his initial applicable Determination Date) or Section 7.1(b)(2)(B)(ii) (during an applicable 2006 Distribution Election Period), as applicable, by such Determination Date or the last day of the 2006 Distribution Election Period, respectively, such Participant shall be considered to have elected a distribution of his or her Career Share Account in a single lump sum as of the First Date Available.

(5)    If an annual installment option is selected, the amount to be distributed in any one-year shall be determined by dividing the Participant’s Career Share Account Balance by the number of years remaining in the elected distribution period.

(6)    Delivery of Shares of Common Stock: The shares of Common Stock that are to be distributed pursuant to section 7.1(a) shall be delivered to an account set up for the Participant’s benefit with a broker/dealer designated by the Company (the “Broker/Dealer Account”). The Common Stock and all Participants remain subject to all applicable legal and regulatory restrictions such as insider trading restrictions and black-out periods.

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7.2 Events Affecting Timing or Amount of Distributions.

(a) “Election” To Accelerate Payment of Career Shares Attributable to 12/10/2003 Performance Share Award. Notwithstanding any provision of Section 7.1 to the contrary, if a Participant had not satisfied his or her MSOR on or before June 30, 2004 (the Determination Date applicable to the 12/10/2003 Performance Share Awards), but as of June 30, 2006 either (i) does satisfy his or her applicable MSOR(s) or (ii) has no applicable MSOR because the participant is longer an Eligible Employee, the Participant will be deemed to have elected as of June 30, 2006 a lump sum payment with respect to the Share or Share Equivalents that would have been credited to the Participant’s Career Share Account as a result of the 12/10/2003 Performance Share Award. Such payment shall be made as of the date that the 12/10/2003 Performance Share Awards otherwise would have become payable if the Participant were not a participant in this Plan.

(b) Special Considerations. Notwithstanding any provision of this Article to the contrary,

(1)    Limited Cashout - if the Participant’s Career Share Account is $10,000 or less on the Participant’s First Date Available (or, if the Participant is not a Key Employee, on the last day of the month coincident with or next following the date that is one (1) month after the date of the Participant’s Termination) (called the “Cashout Date”), the Committee may require that the full value of the Participant’s Career Share Account be distributed as of the Cashout Date in a single, lump sum distribution regardless of the form elected by such Participant, provided that such payment is consistent with the limited cash-out right described in Treasury Regulation Section 1.409A-3(j)(4)(v) or other guidance of the Code in that the payment results in the termination and liquidation of the entirety of the Participant’s interest under each nonqualified deferred compensation plan (including all agreements, methods, programs, or other arrangements with respect to which deferrals of compensation are treated as having been deferred under a single nonqualified deferred compensation plan under Treasury Regulation 1.409A-1(c)(2) or other guidance of the Code) that is associated with this Plan; and the total payment with respect to any such single nonqualified deferred compensation plan is not greater than the applicable dollar amount under Code Section 402(g)(1)(B). Provided, however,

(2)    Avoid Violations - payment to a Participant will be delayed at any time that the Company reasonably anticipates that the making of such payment will violate Federal securities laws or other applicable law; provided however, that any payments so delayed shall be paid at the earliest date at which the Company reasonably anticipates that the making of such payment will not cause such violation.

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ARTICLE VIII

BENEFICIARIES

8.1 Each Participant may designate a beneficiary or beneficiaries who shall receive the balance of the Participant's Career Share Account if the Participant dies prior to the complete distribution of the Participant's Career Share Account. Any designation, or change or rescission of a beneficiary designation shall be made by the Participant’s completion, signature and submission to the Committee of the appropriate beneficiary form prescribed by the Committee. A beneficiary form shall take effect as of the date the form is signed provided that the Committee receives it before taking any action or making any payment to another beneficiary named in accordance with this Plan and any procedures implemented by the Committee. If any payment is made or other action is taken before a beneficiary form is received by the Committee, any changes made on a form received thereafter will not be given any effect. If a Participant fails to designate a beneficiary, or if all beneficiaries named by the Participant do not survive the Participant, the Participant’s Career Share Account will be paid to the Participant’s estate. Unless clearly specified otherwise in an applicable court order presented to the Committee prior to the Participant’s death, the designation of a Participant’s spouse as a beneficiary shall be considered automatically revoked as to that spouse upon the legal termination of the Participant’s marriage to that spouse.

8.2 Distribution to a Participant’s beneficiary shall be in the form of a single lump-sum payment within 60 days after the Committee makes a final determination as to the beneficiary or beneficiaries entitled to receive such distribution.

ARTICLE IX

CLAIMS PROCEDURE

9.1 The following procedures shall apply with respect to claims for benefits under the Plan.

(a) Any Participant or beneficiary who believes he or she is entitled to receive a distribution under the Plan which he or she did not receive or that amounts credited to his or her Account are inaccurate, may file a written claim signed by the Participant, beneficiary or authorized representative with the Claims Reviewer, specifying the basis for the claim. The Claims Reviewer shall provide a claimant with written or electronic notification of its determination on the claim within ninety days after such claim was filed; provided, however, if the Claims Reviewer determines special circumstances require an extension of time for processing the claim, the claimant shall receive within the initial ninety-day period a written notice of the extension for a period of up to ninety days from the end of the initial ninety day period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Plan expects to render the benefit determination.

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(b) If the Claims Reviewer renders an adverse benefit determination under Section 8.1(a), the notification to the claimant shall set forth, in a manner calculated to be understood by the claimant:

(1)    The specific reasons for the denial of the claim;

(2)    Specific reference to the provisions of the Plan upon which the denial of the claim was based;

(3)    A description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary, and

(4)    An explanation of the review procedure specified in Section 9.2, 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 the Employee Retirement Income Security Act of 1974, as amended, following an adverse benefit determination on review.

9.2 The following procedures shall apply with respect to the review on appeal of an adverse determination on a claim for benefits under the Plan.

(a) Within sixty days after the receipt by the claimant of an adverse benefit determination, the claimant may appeal such denial by filing with the Committee a written request for a review of the claim. If such an appeal is filed within the sixty day period, the Committee, or a duly appointed representative of the Committee, shall conduct a full and fair review of such claim that takes into account all comments, documents, records and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The claimant shall be entitled to submit written comments, documents, records and other information relating to the claim for benefits and shall be provided, 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. If the claimant requests a hearing on the claim and the Committee concludes such a hearing is advisable and schedules such a hearing, the claimant shall have the opportunity to present the claimant’s case in person or by an authorized representative at such hearing.

(b) The claimant shall be notified of the Committee’s benefit determination on review within sixty days after receipt of the claimant’s request for review, unless the Committee determines that special circumstances require an extension of time for processing the review. If the Committee determines that such an extension is required, written notice of the extension shall be furnished to the claimant within the initial sixty-day period. Any such extension shall not exceed a period of sixty days from the end of the initial period. The extension notice shall indicate the special circumstances requiring
16

the extension and the date by which the Committee expects to render the benefit determination.

(c) The Committee shall provide a claimant with written or electronic notification of the Plan’s benefit determination on review. The determination of the Committee shall be final and binding on all interested parties. Any adverse benefit determination on review shall set forth, in a manner calculated to be understood by the claimant:

(1)    The specific reason(s) for the adverse determination;

(2)    Reference to the specific provisions of the Plan on which the determination was based;

(3)    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

(4)    A statement of the claimant’s right to bring an action under Section 502(a) of ERISA.

ARTICLE X

MISCELLANEOUS PROVISIONS

10.1 Each Participant agrees that as a condition of participation in the Plan, the Company may withhold applicable federal, state and local taxes, Social Security taxes and Medicare taxes from any deferral and distribution hereunder to the extent that such taxes are then payable.

10.2 In the event the Committee, in its sole discretion, shall find that a Participant or beneficiary is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant or the beneficiary be paid to the duly appointed personal representative of the Participant or beneficiary, and any such payment so made shall be a complete discharge of the liabilities of the Plan and the Company with respect to such Participant or beneficiary.

10.3 The Company intends to continue the Plan indefinitely but reserves the right, in its sole discretion, to modify the Plan from time to time, or to terminate the Plan entirely or to direct the permanent discontinuance or temporary suspension of deferral contributions under the Plan; provided that no such modification, termination, discontinuance or suspension shall reduce the benefits accrued for the benefit of any Participant or beneficiary under the Plan as of the date of such modification, termination, discontinuance or suspension.

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10.4 Nothing in the Plan shall interfere with or limit in any way the right of AEP to terminate any Participant’s employment at any time, or confer upon a Participant any right to continue in the employ of AEP.

10.5 The Company intends the following with respect to this Plan: (1) Section 451(a) of the Code would apply to the Participant's recognition of gross income as a result of participation herein; (2) the Participants will not recognize gross income as a result of participation in the Plan unless and until and then only to the extent that distributions are received; (3) the Company will not receive a deduction for amount credited to any Account unless and until and then only to the extent that amounts are actually distributed; (4) the provisions of Parts 2, 3, and 4 of Subtitle B of Title I of ERISA shall not be applicable; and (5) the design and administration of the Plan are intended to comply with the requirements of Section 409A of the Code, to the extent such section is effective and applicable to amounts deferred hereunder. However, no Eligible Employee, Participant, beneficiary or any other person shall have any recourse against the Corporation, the Company, the Committee or any of their affiliates, employees, agents, successors, assigns or other representatives if any of those conditions are determined not to be satisfied.

10.6 The Plan shall be construed and administered according to the applicable provisions of ERISA and the laws of the State of Ohio.

10.7 Neither a Participant nor any other person shall have any right to sell, assign, transfer, pledge, mortgage or otherwise encumber, transfer, alienate or convey in advance of actual receipt, the amounts, if any, payable under this Plan. Such amounts payable, or any part thereof, and all rights to such amounts payable are not assignable and are not transferable. No part of the amounts payable shall, prior to actual payment, be subject to seizure, attachment, garnishment or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person. Additionally, no part of any amounts payable shall, prior to actual payment, be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency or be transferable to a spouse as a result of a property settlement or otherwise, except that if necessary to comply with a “qualified domestic relations order,” as defined in ERISA Section 206(d), pursuant to which a court has determined that a spouse or former spouse of a Participant has an interest in the Participant’s benefits under the Plan, the Committee shall distribute the spouse’s or former spouse’s interest in the Participant’s benefits under the Plan to such spouse or former spouse in accordance with the Participant’s election under this Plan as to the time and form of payment.

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American Electric Power Service Corporation has caused this amendment and restatement of the American Electric Power System Stock Ownership Requirement Plan to be signed as of this 25th day of September, 2020.

									
	American Electric Power Service Corporation	

	By /s/ Julius Co	
		Julius Cox	
		Senior Vice President and Chief	
		Human Resources Officer	

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Exhibit 10.2

American Electric Power Company, Inc.
Retainer Deferral Plan
For Non-Employee Directors
(As Amended and Restated Effective October 1, 2020)

This document amends and restates effective as of the date executed, the American Electric Power Company, Inc. Retainer Deferral Plan For Non-Employee Directors (the “Plan”), which was most recently was restated effective July 26, 2016.

Article 1
Purpose

The purposes of the Plan are to enable the Company to attract and retain qualified persons to serve as Non-Employee Directors and to provide Non-Employee Directors with an opportunity to defer some or all of their Retainer and all of each type of Retainer Supplement as a means of saving for retirement or other purposes.

Article 2
Effective Date

The Plan was initially effective as of January 1, 1997. The changes made by this amendment and restatement of the Plan were approved by the Board at its meeting held on September 22 2020 (the “Adoption Date”) and generally take effect as of the Adoption Date.

Article 3
Definitions

Whenever used in the Plan, the following terms shall have the respective meanings set forth below:

3.1    “Account” means, with respect to each Participant, the Participant’s separate individual memo account established and maintained for the exclusive purpose of accounting for the Participant’s deferred Retainers and Retainer Supplements. The portion of the Account attributable to Retainers earned prior to January 1, 2005 (which has been accrued in terms of Stock Units) shall be referred to as the Participant’s “Pre-2005 Account.” The portion of the Account attributable to Retainers earned after January 1, 2005 and Retainer Supplements earned on and after January 1, 2008 shall be referred to as the Participant’s “Post-2004 Account.”

3.2    “Beneficiary” means, with respect to each Participant, the recipient or recipients designated by the Participant who are, upon the Participant’s death, entitled in accordance with the Plan’s terms to receive the benefits to be paid with respect to the Participant.

3.3    “Board” means the Board of Directors of the Company.

3.4    “Change in Control” means a change in control of the Company as provided under Section 409A(a)(2)(A)(v) of the Code.

3.5    “Code” means the Internal Revenue Code of 1986, as amended from time to time.

3.6    “Committee” means the Committee on Directors and Corporate Governance of the Board.

3.7    “Common Stock” means the common stock, $6.50 par value, of the Company.

3.8    “Company” means American Electric Power Company, Inc., a New York corporation, and any successor thereto.

3.9    “Contributions” means contributions made by the Participant pursuant to an executed Retainer Deferral Agreement attributable to Retainers earned on or after January 1, 2005 and Retainer Supplements earned on or after January 1, 2008.

3.10    “Director” means an individual who is a member of the Board.

3.11    “First Date Available” means (a) with respect to Specified Directors, the later of (i) the date that is eighteen (18) months following the Adoption Date, or (ii) the date that is six (6) months after the date of the Participant’s Termination; and (b) with respect to all other Participants, the date of the Participant’s Termination.

3.12    “Fund” means the investment options made available to participants in the American Electric Power System Incentive Compensation Deferral Plan, as revised from time to time.

3.13    “Investment Income” means the earnings, gains and losses that would be attributable to the investment of such Contributions in a Fund or Funds.

3.14    “Market Value” means the closing price of the Common Stock, as reported on the NASDAQ Stock Market LLC on the date in question or, if the Common Stock shall not have been traded on such date or if the NASDAQ Stock Market LLC is closed on such date, then the first day prior thereto on which the Common Stock was so traded.

3.15    “Non-Employee Director” means any person who serves on the Board and who is not an officer of the Company or employee of its Subsidiaries.

3.16    “Participant” means any Non-Employee Director who has made an election to defer payment of all or a portion of such person’s Retainer or Retainer Supplements in accordance with the terms of this Plan.

3.17    “Plan Year” means the twelve-month period commencing each January 1 and ending December 31.
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3.18    “Retainer” means the designated annual cash retainer, currently paid quarterly, for Non-Employee Directors established from time to time by the Board as annual compensation for services rendered, exclusive of compensation for service as a member of any committee designated by the Board or in connection with any meeting of the Board or special assignment, and exclusive of reimbursements for expenses incurred in performance of service as a Director, and excluding particularly all Retainer Supplements and amounts representing per diems or reimbursements for expenses.

3.19    “Retainer Deferral Agreement” means a written election signed by the Participant and submitted to the Company by which the Participant irrevocably elects in accordance with the terms of this Plan to reduce his or her Retainer or Retainer Supplements for the Plan Year and to have the Company treat the amount of the reduction as a Contribution to this Plan.

3.20    “Retainer Supplements” means the amounts other than the Retainer, currently paid quarterly, for Non-Employee Directors established from time to time by the Board for serving as a committee member, for serving as the chair of a committee, for serving as the presiding director or as a per diem to compensate a Non-Employee Director for special additional services beyond those contemplated by the Retainer, but excluding amounts representing reimbursements for expenses.

3.21    “Specified Director” means a Participant who is classified as a “specified employee” at the time of Termination in accordance with the policies adopted by the Human Resources Committee of the Board in order to comply with the requirements of Section 409A(a)(2)(B)(i) of the Code and the guidance issued thereunder.

3.22    “Stock Unit” means a measure of value, expressed as a share of Common Stock, credited to a Participant under this Plan. No certificates shall be issued with respect to such Stock Units, but the Company shall maintain a bookkeeping Account in the name of the Participant to which the Stock Units shall relate.

3.23    “Subsidiary” means any corporation in which the Company owns directly or indirectly through its Subsidiaries, at least 50 percent of the total combined voting power of all classes of stock, or any other entity (including, but not limited to, partnerships and joint ventures) in which the Company owns at least 50 percent of the combined equity thereof.

3.24    “Termination” means termination of services as a Director for any reason.

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Article 4
Election to Defer Retainer

4.1    Election

(a)On or before December 31 of any year, a Non-Employee Director may elect, by filing with the Company a Retainer Deferral Agreement, to defer receipt of all or a specified portion of the Director’s Retainer or, effective commencing with the Plan Year beginning January 1, 2008, to defer receipt of all of each type of Retainer Supplement payable for subsequent Plan Years, beginning with the Plan Year that begins after the date of such election.

(b)Notwithstanding the provisions of paragraph (a), a Non-Employee Director elected to fill a vacancy on the Company’s Board and who was not a Director on the last day of the preceding Plan Year, or whose term of office did not begin until after that date, may file a Retainer Deferral Agreement, to defer receipt of all or a specified portion of the Director’s Retainer or, effective commencing with the Plan Year beginning January 1, 2008, to defer receipt of all of each type of Retainer Supplement, payable for the remainder of such Plan Year, provided such Retainer Deferral Agreement is filed within 30 days after the beginning of his or her term of office and shall apply only to such portion of the Retainer and Retainer Supplements as relates to services to be performed, and as would not otherwise become payable until, after the date such Retainer Deferral Agreement is filed.

(c)An election made pursuant to a Retainer Deferral Agreement filed in accordance with this Section 4.1 shall defer the Director’s receipt of payment to a date or dates on or after the Director’s Termination as specified in the distribution election submitted in accordance with Article 7.

4.2    Revocation of Election

An effective election pursuant to Section 4.1 may not be revoked or modified (except as otherwise stated herein) with respect to the Retainer and Retainer Supplements payable for a Plan Year or portion of a Plan Year for which such election is effective. An effective election may be terminated or modified for any subsequent Plan Year by the filing of an election, on or before the last day of the preceding Plan Year for which such modification or termination is to be effective.

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4.3    Retainer Deferral Election

(a)Pre-2005 Deferrals. When a Participant effectively elected to defer all or a portion of the Participant’s Retainer earned prior to January 1, 2005, such deferral was effectuated in Stock Units. The number of whole and fractional Stock Units were computed to three decimal places and credited to the Participant’s Pre-2005 Account on the date the deferred Retainer would otherwise have been payable to the Participant, based on an amount equal to the dollar amount of the deferred Retainer which otherwise would have been payable to the Participant divided by the Market Value on such date.

(b)Post-2004 Deferrals. When a Participant effectively elects to defer all or a portion of the Participant’s Retainer earned on or after January 1, 2005 and, effective commencing January 1, 2008, some or all of the Participant’s Retainer Supplements, such deferral shall be credited to the Participant’s Post-2004 Account as of the date the Retainer or Retainer Supplements, as appropriate, otherwise would have been paid to such Participant.

Article 5
Dividends and Adjustments to Pre-2005 Account

5.1    Reinvestment of Dividends

On each dividend payment date with respect to the Common Stock, the Pre-2005 Account of a Participant, with Stock Units held pursuant to Article 4, shall be credited with an additional number of whole and fractional Stock Units, computed to three decimal places, equal to the product of the dividend per share then payable, multiplied by the number of Stock Units then credited to such Pre-2005 Account, divided by the Market Value on the dividend payment date.

5.2    Adjustments

The number of Stock Units credited to a Participant’s Pre-2005 Account pursuant to Article 4 shall be appropriately adjusted for any change in the Common Stock by reason of any merger, reclassification, consolidation, recapitalization, stock dividend, stock split or any similar change affecting the Common Stock.

5.3    Conversion of Stock Units to AEP Stock Fund

Effective as of March 15, 2005, the Stock Units credited to a Participant’s Pre-2005 Account shall be converted into units in the Fund that determines its value and Investment Income primarily by reference to Common Stock (the “AEP Stock Fund”).

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Article 6
Earnings of Post-2004 Account and Converted Pre-2005 Account

6.1    Investment of Contributions

Contributions added to a Participant’s Post-2004 Account shall be credited with earnings as if invested in the Funds selected by the Participant. To the extent the Participant fails to select Funds for the investment of Contributions under the Plan, the Participant shall be deemed to have selected the Fund that the Committee has designated as the Default Fund. The Participant may change the selected Funds by providing notification in accordance with the Plan’s procedures. Any change in the Funds selected by the Participant shall be implemented in accordance with the Plan’s procedures.

6.2    Changing Investments

A Participant may elect to transfer all or a portion of the amounts credited to the Participant’s Post-2004 Account and, after its conversion in accordance with Section 5.3, the Participant’s Pre-2005 Account from any Fund or Funds to any other Fund or Funds by providing notification in accordance with the Plan’s procedures. Such transfers between Funds may be made in any whole percentage or dollar amounts and shall be implemented in accordance with the Plan’s procedures.

6.3    Valuation of Account

The amount credited to each Participant's Post-2004 Account and, after its conversion in accordance with Section 5.3, the Participant’s Pre-2005 Account shall be determined daily based upon the fair market value of such Fund or Funds. The fair market value calculation for a Participant's Account shall be made after all Contributions, distributions, Investment Income and transfers for the day are recorded. A Participant’s Account, as adjusted from time to time, shall continue to be credited with Investment Income until the balance of the Account is zero and no additional Contributions are anticipated from such Participant by the Committee.

Article 7
Payment

7.1    Manner of Payment Upon Termination

(a)All amounts credited to a Participant’s Account shall be paid to the Participant in accordance with the Participant’s effective election in one of the following forms

(i)A single lump sum distribution
(A)as of the First Date Available; or
(B)as of the fifth anniversary of the First Date Available; or

(ii)In five (5) annual installments commencing
(A)as of the First Date Available; or
(B)as of the fifth anniversary of the First Date Available; or
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(iii)In ten (10) annual installments commencing as of the First Date Available.

(b)For this purpose, a Participant’s election under Section 7.1 shall not be effective unless all of the following requirements are satisfied.

(i)The election is submitted to the Company in writing in a form determined by the Committee to be acceptable;

(ii)The election is submitted timely. For purposes of this Section 7.1(b)(ii), a distribution election will be considered “timely” only if it satisfies the requirements of (A), (B) or (C), below, as may be applicable:
(A)Within the applicable timeframes set forth in Section 4.1, but only if the distribution election is submitted in connection with the Participant’s initial Retainer Deferral Agreement under this Plan; or
(B)During the 2005 Distribution Election Period, but only with regard to the first distribution election form submitted by such Participant during that period. For this purpose, the “2005 Distribution Election Period” shall such period during which Participant’s are given the opportunity to select among the options set forth in Section 7.1(a), provided that such period shall end no later than December 31, 2005 or, with respect to a particular Participant, such earlier date of such Participant’s Termination; or
(C)At least one year prior to the date of the Participant’s Termination.

(iii)Unless submitted under the terms and conditions described in Section 7.1(b)(ii)(A) or (B), the election makes a permissible change in the distribution option selected. A change in the distribution option will be considered permissible for purposes of the immediately preceding sentence only if the new distribution election selects an option that (A) results in the deferral of the first scheduled payment by at least 5 years and (B) does not result in the acceleration of any scheduled payment that would have been made under the distribution election that had been on file with respect to such Participant’s Account.

(c)If a Participant fails to submit a distribution election that satisfies the requirements of this Section 7.1, the Participant’s Account shall be distributed in a single lump sum as of the First Date Available.

(d)For purposes of this Section 7.1, the amount to be distributed to a Participant shall be based upon the value of the Participant’s Account determined as of the applicable distribution date (or, if that is not a business day, then as of the next business day thereafter) and shall be paid to such Participant as soon as administratively practicable thereafter.

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7.2    Manner of Payment Upon Death

Notwithstanding the Participant’s election, if a Participant dies while amounts remain credited to the Participant’s Account, the balance of the Account will be paid in a lump sum in cash as soon as reasonably practicable after the date of the Participant’s death to the Beneficiary or the Participant’s estate, as the case may be.

7.3    Determination of Cash Payments Attributable to Stock Units

Any cash payments of Stock Units shall be calculated on the basis of the average of the Market Value of the Common Stock for the last 20 trading days prior to the Participant’s Termination, deferred distribution date, respective installment payment dates or the date of the Participant’s death, as the case may be.

Article 8
Beneficiary Designation

Each Participant shall be entitled to designate a Beneficiary or Beneficiaries (which may be an entity other than a natural person) who, following the Participant’s death, will be entitled to receive any payments to be made under Section 7.2. At any time, and from time to time, any designation may be changed or cancelled by the Participant without the consent of any Beneficiary. Any designation, change, or cancellation must be by written notice filed with the Company and shall not be effective until received by the Company. Payment shall be made in accordance with the last unrevoked written designation of Beneficiary that has been signed by the Participant and delivered by the Participant to the Company prior to the Participant’s death. If the Participant designates more than one Beneficiary, any payments under Section 7.2 to the Beneficiaries shall be made in equal shares unless the Participant has designated otherwise, in which case the payments shall be made in the proportions designated by the Participant. If no Beneficiary has been named by the Participant or if all Beneficiaries predecease the Participant, payment shall be made to the Participant’s estate.

Article 9
Transferability Restrictions

The Plan shall not in any manner be liable for, or subject to, the debts and liabilities of any Participant or Beneficiary. No payee may assign any payment due such party under the Plan. No benefits at any time payable under the Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, attachment, garnishment, levy, execution, or other legal or equitable process, or encumbrance of any kind.

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Article 10
Funding Policy

The Plan is an unfunded non-qualified deferred compensation plan and therefore the Contributions credited to a Participant's Account and the investment of those Contributions in Stock Units or the Fund or Funds selected by the Participant are memo accounts that represent general, unsecured liabilities of the Company payable exclusively out of the general assets of the Company. In the event that the Company becomes insolvent, the Participants shall be considered as general unsecured creditors of the Company. The Participant’s rights to benefits under this Plan shall not be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge encumbrance, attachment or garnishment by creditors of any Participant or any beneficiary.

Article 11
Change in Control

Notwithstanding any provision of this Plan to the contrary, if a Change in Control of the Company occurs, each Participant’s Account will be paid in a lump sum in cash, to the Participant, not later than 15 days after the date of such Change in Control.

In addition, the Company shall reimburse a Participant for the legal fees and expenses incurred if the Participant is required to seek to obtain or enforce any right to distribution. Notwithstanding any provisions of this Plan to the contrary, the provisions of this Article may not be amended by an amendment effected within three years following a Change in Control.

Article 12
Administration

The Plan shall be administered by the Committee. The Committee shall have authority to interpret the Plan, and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. The Committee may employ agents, attorneys, accountants, or other persons (who also may be employees of a Subsidiary) and allocate or delegate to them powers, rights and duties, all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.

Article 13
Amendment and Termination

By resolution duly adopted by the Board, the Company (or such person as may be designated in such resolution), shall have the right, authority and power to alter, amend, modify, revoke, or terminate the Plan; except as provided in Article 11. The Company specifically reserves the right to modify the terms and conditions of any election made pursuant to the Plan to the extent the Company determines it is permissible and necessary to cause such change to the elections to be consistent with the requirements imposed by the Code. Notwithstanding the foregoing
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provisions of this Article 13, no amendment or termination of the Plan or of any election shall adversely affect the rights of any Participant with respect to any amount then credited to such Participant’s Account, unless the Participant shall consent thereto in writing.

Article 14
Miscellaneous

14.1    No Right to Continue as a Director

Nothing in this Plan shall be construed as conferring upon a Participant any right to continue as a member of the Board.

14.2    No Interest as a Shareholder

Neither Stock Units nor amounts credited to the AEP Stock Fund give a Participant any rights whatsoever with respect to shares of Common Stock.

14.3    No Right to Corporate Assets

Nothing in this Plan shall be construed as giving the Participant, the Participant’s designated Beneficiaries or any other person any equity or interest of any kind in the assets of the Company or any Subsidiary or creating a trust of any kind or a fiduciary relationship of any kind between the Company or any Subsidiary and any person. As to any claim for payments due under the provisions of the Plan, a Participant, Beneficiary and any other persons having a claim for payments shall be unsecured creditors of the Company.

14.4    Payment to Legal Representative for Participant

In the event the Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant be paid to the Participant’s duly appointed legal representative, and any such payment so made shall be a complete discharge of the liabilities of the Plan and the Company.

14.5    No Limit on Further Corporate Action

Nothing contained in the Plan shall be construed so as to prevent the Company or any Subsidiary from taking any corporate action which is deemed by the Company or any Subsidiary to be appropriate or in its best interest.

14.6    Governing Law

The Plan shall be construed and administered according to the laws of the State of New York to the extent that those laws are not preempted by the laws of the United States of America.

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14.7    Headings

The headings of articles, sections, subsections, paragraphs or other parts of the Plan are for convenience of reference only and do not define, limit, construe, or otherwise affect its contents.

Signed this 25th day of September, 2020.

AMERICAN ELECTRIC POWER COMPANY, INC.

By /s/ Thomas G. Berkemeyer
Thomas G. Berkemeyer, Assistant Secretary
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Exhibit 10.3

American Electric Power Company, Inc.
Stock Unit Accumulation Plan
For Non-Employee Directors
(As Amended Effective October 1, 2020)

Article 1
Purpose

The purposes of this American Electric Power Company, Inc. Stock Unit Accumulation Plan For Non-Employee Directors (the “Plan”) are to enable the Company to attract and retain qualified persons to serve as Non-Employee Directors, to solidify the common interests of its Non-Employee Directors and shareholders by enhancing the equity interest of Non-Employee Directors in the Company, and to encourage the highest level of Non-Employee Director performance by providing such Non-Employee Directors with a proprietary interest in the Company’s performance and progress by providing a portion of the compensation of the Non-Employee Directors in deferred Stock Units.

Article 2
Effective Date

The Plan became effective as of January 1, 1997. The changes made by this amendment and restatement of the Plan were approved by the Board at its meeting held on September 22, 2020 (the “Adoption Date”) and generally take effect as of the Adoption Date.

Article 3
Definitions

Whenever used in the Plan, the following terms shall have the respective meanings set forth below:

3.1    “Account” means, with respect to each Participant, the Participant’s separate individual account established and maintained for the exclusive purpose of accounting for the Participant’s awards under the Plan. The Account shall consist of two (2) separate sub-accounts: a Stock Unit Account and an Investment Account.

3.2    “Beneficiary” means, with respect to each Participant, the recipient or recipients designated by the Participant who are, upon the Participant’s death, entitled in accordance with the Plan’s terms to receive the benefits to be paid with respect to the Participant.

3.3    “Board” means the Board of Directors of the Company.

3.4    “Cash Retainer” means the designated annual cash retainer, paid quarterly, for Non-Employee Directors established from time to time by the Board as annual compensation for services rendered, exclusive of compensation for service as a member of any

committee designated by the Board or in connection with any meeting of the Board or special assignment, and exclusive of reimbursements for expenses incurred in performance of service as a Director.

3.5    “Code” means the Internal Revenue Code of 1986, as amended.

3.6    “Committee” means the Committee on Directors and Corporate Governance of the Board.

3.7    “Common Stock” means the common stock, $6.50 par value, of the Company.

3.8    “Company” means American Electric Power Company, Inc., a New York corporation, and any successor thereto.

3.9    “Contributions” means contributions made by the Company to a Participant’s Account pursuant to Article 4.

3.10    “Director” means an individual who is a member of the Board.

3.11    “Equity Retainer” means the designated annual stock retainer, payable quarterly, for Non-Employee Directors established from time to time by the Board as equity compensation for services rendered. An Equity Retainer may be in the form of Stock Units pursuant to Article 4(a) or as an amount credited to the AEP Stock Fund pursuant to Article 4(b).

3.12    “First Date Available” means (a) with respect to Specified Directors, the later of (i) the date that is eighteen (18) months following the Adoption Date, or (ii) the date that is six (6) months after the date of the Participant’s Termination; and (b) with respect to all other Participants, the date of the Participant’s Termination.

3.13    “Fund” means the same investment options made available to participants in the American Electric Power System Incentive Compensation Deferral Plan, as revised from time to time.

3.14    “Investment Account” means that portion of a Participant’s Account attributable to Contributions made by the Company pursuant to Article 4(b).

3.15    “Investment Income” means the earnings, gains and losses that would be attributable to the investment of the Investment Account in a Fund or Funds.

3.16    “Market Value” means the closing price of the Common Stock, as reported on the NASDAQ Stock Market LLC on the date in question or, if the Common Stock shall not have been traded on such date or if the NASDAQ Stock Market LLC is closed on such date, then the first day prior thereto on which the Common Stock was so traded.

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3.17    “Non-Employee Director” means any person who serves on the Board and who is not an officer of the Company or employee of its Subsidiaries.

3.18    “Participant” means any Non-Employee Director who has received an Equity Retainer award.

3.19    “Retainer” means Cash Retainer and Equity Retainer.

3.20    “Specified Director” means a Participant who is classified as a “specified employee” at the time of Termination in accordance with the policies adopted by the Human Resources Committee of the Board in order to comply with the requirements of Section 409A(a)(2)(B)(i) of the Code and the guidance issued thereunder.

3.21    “Stock Unit” means a measure of value, expressed as a share of Common Stock, credited to a Participant under this Plan. No certificates shall be issued with respect to such Stock Units, but the Company shall maintain a bookkeeping Account in the name of the Participant to which the Stock Units shall relate.

3.22    “Subsidiary” means any corporation in which the Company owns directly or indirectly through its Subsidiaries, at least 50 percent of the total combined voting power of all classes of stock, or any other entity (including, but not limited to, partnerships and joint ventures) in which the Company owns at least 50 percent of the combined equity thereof.

3.23    “Termination” means retirement from the Board or termination of service as a Director for any other reason.

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Article 4
Annual Equity Retainer Awards

The Equity Retainer shall be credited quarterly and shall equal the dollar amount of the Equity Retainer payable to the Participant.

(a)For the first twenty quarters of a Participant’s period of service as a Director, the Equity Retainer shall be contributed to the Participant’s Stock Unit Account in the form of Stock Units. The number of such Stock Units to be credited quarterly shall be determined by dividing the amount of the Equity Retainer credited quarterly by the Market Value on such date. The number of whole and fractional Stock Units will be computed to three decimal places.

(b)After the period described in Article 4(a), the Equity Retainer shall be contributed to the AEP Stock Fund maintained in the Participant’s Investment Account.

Article 5
Investments and Adjustments

5.1    Stock Unit Account

(a)Dividends. On each dividend payment date with respect to the Common Stock, the Stock Unit Account of a Participant, with Stock Units held pursuant to Article 4(a), shall be credited with an additional number of whole and fractional Stock Units, computed to three decimal places, equal to the product of the dividend per share then payable, multiplied by the number of Stock Units then credited to such Stock Unit Account, divided by the Market Value on the dividend payment date.

(b)Adjustments. The number of Stock Units credited to a Participant’s Stock Unit Account pursuant to Article 4(a) shall be appropriately adjusted for any change in the Common Stock by reason of any merger, reclassification, consolidation, recapitalization, stock dividend, stock split or any similar change affecting the Common Stock.

5.2    Investment Account

(a)Investment of Contributions. Contributions added to a Participant’s Investment Account shall be credited to the AEP Stock Fund and credited with earnings as if invested in the AEP Stock Fund.

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(b)Changing Investments. A Participant may elect to transfer all or a portion of the amounts credited to the Participant’s Investment Account from any Fund or Funds to any other Fund or Funds by providing notification in accordance with the Plan’s procedures. Such transfers between Funds may be made in any whole percentage or dollar amounts and shall be implemented in accordance with the Plan’s procedures.

(c)Valuation of Account. The balance of each Participant's Investment Account shall be determined daily based upon the fair market value of such Fund or Funds. The fair market value calculation for a Participant's Investment Account shall be made after all distributions, Investment Income and transfers for the day are recorded. A Participant’s Account, as adjusted from time to time, shall continue to be credited with Investment Income until the balance of the Investment Account is zero and no additional Contributions are anticipated for such Participant by the Committee.

Article 6
Payment of Stock Units

6.1    Manner of Payment Upon Termination

(a)All amounts credited to a Participant’s Stock Unit Account and all amounts credited to such Participant’s Investment Account shall be paid to the Participant in accordance with the Participant’s effective election as to such sub-account in one of the following forms

(i)A single lump sum distribution
(A)as of the First Date Available; or
(B)as of the fifth anniversary of the First Date Available; or

(ii)In five (5) annual installments commencing
(A)as of the First Date Available; or
(B)as of the fifth anniversary of the First Date Available; or

(iii)In ten (10) annual installments commencing as of the First Date Available.

(b)For this purpose, a Participant’s election under Section 6.1 shall not be effective unless all of the following requirements are satisfied.

(i)The election is submitted to the Company in writing in a form determined by the Committee to be acceptable;

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(ii)The election is submitted timely. For purposes of this Section 6.1(b)(ii), a distribution election will be considered “timely” only if it satisfies the applicable requirements:
(A)As to an election applicable to the Participant’s Stock Unit Account, any of (1), (2) or (3), as may be applicable
(1)Within 30 days after the beginning of his or her initial term of office as a Director; or
(2)During the 2007 Distribution Election Period, but only with regard to the last distribution election form submitted by such Participant during such a period as is applicable to that Participant. For this purpose, the “2007 Distribution Election Period” shall be such period during which one or more Participants are given the opportunity to select among the options set forth in Section 6.1(a), provided that such period shall end no later than December 31, 2007 or, with respect to a particular Participant, such earlier date of such Participant’s Termination; or
(3)At least one year prior to the date of the Participant’s Termination.
(B)As to an election applicable to the Participant’s Investment Account, any of (1), (2) or (3), as may be applicable
(1)No later than the last day of the calendar year immediately preceding the commencement of the twenty-first quarter of the Participant’s period of service as a Director ; or
(2)During the 2012 Distribution Election Period, but only with regard to the last distribution election form submitted by such Participant during such a period as is applicable to that Participant. For this purpose, the “2012 Distribution Election Period” shall be such period during which one or more Participants are given the opportunity to select among the options set forth in Section 6.1(a), provided that such period shall end no later than December 31, 2012; or

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(3)At least one year prior to the date of the Participant’s Termination.

(iii)Unless submitted under the terms and conditions described in Section 6.1(b)(ii)(A)(1) or (2) or (B)(1) or (2), the election makes a permissible change in the distribution option selected. A change in the distribution option will be considered permissible for purposes of the immediately preceding sentence only if the new distribution election selects an option that results in the deferral of the first scheduled payment by at least 5 years. For purposes of compliance with the rule set forth in Section 409A(a) of the Code (and the regulations issued thereunder), each distribution option described in Section 6.1(a) shall be treated as a single payment as of the first scheduled payment date.

(iv)If the Participant is submitting the election pursuant to paragraph (b)(ii)(A)(2) to change the timing or form of distribution that is then in effect with respect to the Participant’s Career Share Account, the newly selected option may not defer payments that the Participant would have received in 2007 if not for the new distribution election nor cause payments to be made in 2007 if not for the new distribution election.

(c)For purposes of Section 6.1(b), if a Participant’s effective distribution election form with respect to the participant’s Stock Unit Account was submitted using the options that had been made available under the Plan as in effect prior to January 1, 2005 [i.e., as either (A) a single lump-sum payment, or in annual installment payments over not more than ten years; (B) commencing within 10 days after the date of the Participant’s Termination or up to five years after the Participant’s Termination], then:

(i)If the Participant’s Termination occurs prior to the expiration of the 2007 Distribution Election Period last applicable to the Participant, the Participant’s effective distribution election form shall be given full effect; and

(ii)If the Participant’s Termination occurs after the expiration of the 2007 Distribution Election Period last applicable to such Participant, the Participant shall be considered to have elected the corresponding option as set forth in Section 6.1(a).

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(d)If a Participant fails to submit an effective distribution election with regard to his Stock Unit Account or Investment Account that satisfies the requirements of Section 6.1(b)(ii)(A)(1) (upon commencement of initial term) or Section 6.1(b)(ii)(A)(2) or (B)(1) or (2) (during an applicable Distribution Election Period), as applicable, by the applicable due date, such Participant shall be considered to have elected a distribution of that portion of his or her Account in a single lump sum as of the First Date Available.

6.2    Manner of Payment Upon Death

Notwithstanding the Participant’s election, if a Participant dies while amounts remain credited to the Participant’s Account, the balance of the Account will be paid in a lump sum in cash as soon as reasonably practicable after the date of the Participant’s death to the Beneficiary or the Participant’s estate, as the case may be.

6.3    Determination of Cash Payments Attributable to Stock Units and Funds

The amount to be distributed pursuant to Section 6.1 or 6.2 shall be based upon the value of the Stock Units and Funds in the Participant’s Account determined as of the applicable distribution date (or, if that is not a business day, then as of the business day immediately prior thereto) and shall be paid to such Participant as soon as administratively practicable thereafter. The value of Stock Units shall be calculated on the basis of the average of the Market Value of the Common Stock for the last 20 trading days prior to the applicable distribution date.

6.4    Avoiding Violation of Applicable Law

Notwithstanding any provision of this Article to the contrary, payment to a Participant will be delayed at any time that the Company reasonably anticipates that the making of such payment will violate Federal securities laws or other applicable law; provided however, that any payments so delayed shall be paid at the earliest date at which the Company reasonably anticipates that the making of such payment will not cause such violation.

Article 7
Beneficiary Designation

Each Participant shall be entitled to designate a Beneficiary or Beneficiaries (which may be an entity other than a natural person) who, following the Participant’s death, will be entitled to receive any payments to be made under Section 6.2. At any time, and from time to time, any designation may be changed or cancelled by the Participant without the consent of any Beneficiary. Any designation, change, or cancellation must be by written notice filed with the Company and shall not be effective until received by the Company. Payment shall be made in accordance with the last unrevoked written designation of Beneficiary that has been signed by the Participant and delivered by the Participant to the Company prior to the Participant’s death. If the Participant designates more than one Beneficiary, any payments under Section 6.2 to the Beneficiaries shall be made in equal shares unless the Participant has designated otherwise, in
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which case the payments shall be made in the proportions designated by the Participant. If no Beneficiary has been named by the Participant or if all Beneficiaries predecease the Participant, payment shall be made to the Participant’s estate.

Article 8
Transferability Restrictions

The Plan shall not in any manner be liable for, or subject to, the debts and liabilities of any Participant or Beneficiary. No payee may assign any payment due such party under the Plan. No benefits at any time payable under the Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, attachment, garnishment, levy, execution, or other legal or equitable process, or encumbrance of any kind.

Article 9
Funding Policy

The Company’s obligations under the Plan shall be totally unfunded so that the Company or any Subsidiary is under merely a contractual duty to make payments when due under the Plan. The promise to pay shall not be represented by notes and shall not be secured in any way.

Article 10
Change in Control

Notwithstanding any provision of this Plan to the contrary, if a “Change in Control” (as defined below) of the Company occurs, amounts credited to a Participant’s Account, whether vested or unvested and forfeitable, will be paid in a lump sum in cash to the Participant not later than 15 days after the date of the Change in Control. For this purpose, the balance in the Stock Unit Account shall be determined by the higher of (a) the average of the Market Value of the Common Stock for the last 20 trading days prior to such Change in Control or (b) if the Change in Control of the Company occurs as a result of a tender or exchange offer or consummation of a corporate transaction, then the highest price paid per share of Common Stock pursuant thereto. Any consideration other than cash forming a part or all of the consideration for the Common Stock to be paid pursuant to the applicable transaction shall be valued at the valuation price thereon determined by the Board.

In addition, the Company shall reimburse a Participant for the legal fees and expenses incurred if the Participant is required to seek to obtain or enforce any right to distribution. In the event that it is determined that such Participant is properly entitled to a cash distribution hereunder, such Participant shall also be entitled to interest thereon at the prime rate of interest as published in The Wall Street Journal plus two percent from the date such distribution should have been made to and including the date it is made. Notwithstanding any provisions of this Plan to the contrary, the provisions of this Article may not be amended by an amendment effected within three years following a Change in Control.

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A “Change in Control” means a change in control of the Company as provided under Section 409A(a)(2)(A)(v) of the Code.

Article 11
Administration

The Plan shall be administered by the Committee. The Committee shall have the authority and discretion to interpret the Plan, and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. The Committee may employ agents, attorneys, accountants, or other persons (who also may be employees of a Subsidiary) and allocate or delegate to them powers, rights, and duties, all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.

Article 12
Amendment and Termination

The Company, by resolution duly adopted by the Board, shall have the right, authority and power to alter, amend, modify, revoke, or terminate the Plan; except as provided in Article 10; and provided further, that no amendment or termination of the Plan shall adversely affect the rights of any Participant with respect to any amount then credited to such Participant’s Account, unless the Participant shall consent thereto in writing.

Article 13
Miscellaneous

13.1    No Right to Continue as a Director

Nothing in this Plan shall be construed as conferring upon a Participant any right to continue as a member of the Board.

13.2    No Interest as a Shareholder

Neither Stock Units nor credits to the AEP Stock Fund shall give a Participant any rights whatsoever with respect to shares of Common Stock.

13.3    No Right to Corporate Assets

Nothing in this Plan shall be construed as giving the Participant, the Participant’s designated Beneficiaries or any other person any equity or interest of any kind in the assets of the Company or any Subsidiary or creating a trust of any kind or a fiduciary relationship of any kind between the Company or any Subsidiary and any person. As to any claim for payments due under the
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provisions of the Plan, a Participant, Beneficiary and any other persons having a claim for payments shall be unsecured creditors of the Company or any Subsidiary.

13.4    Payment to Legal Representative for Participant

In the event the Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant be paid to the Participant’s duly appointed legal representative, and any such payment so made shall be a complete discharge of the liabilities of the Plan.

13.5    No Limit on Further Corporate Action

Nothing contained in the Plan shall be construed so as to prevent the Company or any Subsidiary from taking any corporate action which is deemed by the Company or any Subsidiary to be appropriate or in its best interest.

13.6    Governing Law

The Plan shall be construed and administered according to the laws of the State of New York to the extent that those laws are not preempted by the laws of the United States of America.

13.7    Headings

The headings of articles, sections, subsections, paragraphs or other parts of the Plan are for convenience of reference only and do not define, limit, construe, or otherwise affect its contents.

Signed this 25th day of September, 2020.

AMERICAN ELECTRIC POWER COMPANY, INC.

By /s/ Thomas G. Berkemeyer
Thomas G. Berkemeyer, Assistant Secretary
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Exhibit 10.4

SEVERANCE, STOCK AWARD, RELEASE OF ALL CLAIMS AND
NONCOMPETITION AGREEMENT

This Severance, Stock Award, Release of All Claims and Noncompetition Agreement ("Agreement") is entered into by and between Lana L. Hillebrand, herein after referred to, together with 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".

In consideration of the promises set forth in this Agreement, Employee and the Company agree as follows:

1. Termination of Employment; Resignation. The parties acknowledge that Employee’s employment relationship with the Company will cease at the close of business on December 31, 2020 or such other date that Employee and the Company mutually agree (the “Termination Date”). Pending the Termination Date, the Company reserves the right to change the responsibilities of Employee. Employee hereby resigns effective at the close of business on the Termination Date, (a) as an employee of the Company, (b) to the extent she has not already then done so, from all Company boards, committees, and offices, including those of any parent, affiliate or subsidiary of the Company, and (c) from all administrative, fiduciary or other positions Employee may hold or have held relating to the Company. The Company consents to and accepts all such resignations. Employee agrees to make herself available for assigned duties and adhere to Company policy through and including the Termination Date. Employee further agrees to execute a release comparable to that set forth in this Agreement following her Termination Date.

2. Severance Payments. The Company shall provide:

(a)Employee (or Employee’s estate) a salary and bonus severance in the amount of $1,106,875 (the “Severance Amount”). The Company shall pay the Severance Amount to Employee according to the following payment schedule:

(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 Termination Date, a payment of $553,437.50; and

(ii)The balance of such Severance Amount shall be paid in 13 equal bi-weekly installments as of such number of subsequent regular payroll dates of the Company.

Payment under this Section 2 shall be made by direct deposit, mailing to the last address provided by Employee to the Company or such other reasonable method as determined by the Company. Each payment shall be subject to such deductions as required by law that is not deducted from other amounts paid or payable to Employee.

(b)If Employee timely executes and returns this Agreement and continues to provide services to AEP up to and including the Termination Date, prorated severance vesting shall apply to Employee’s outstanding Restricted Stock Units (“RSU”). Severance vesting will also apply to Employee’s Performance Shares under the terms the applicable Performance Share Award Agreements, provided that employee works up to and including the Termination Date. Any RSUs and Performance Shares that do not vest upon employment termination will be canceled. All applicable tax withholding will apply to any RSU and Performance Share payments based on Employee’s last work location.

(c)Employee (or her surviving covered dependents) will have the option to continue medical and dental coverage at a reduced rate for up to twelve (12) months (i) under COBRA or (ii) if Employee is eligible for AEP retiree medical and/or dental benefits as of his or her Employment Termination Date, under the terms of the applicable retiree medical and/or dental benefit plan, as amended from time to time; provided, however, that such reduced rate shall cease at such time as Employee (or surviving covered dependent) is eligible for medical coverage either through Medicare or some other public program or through subsequent employment, whichever comes first, and whether or not Employee or dependent actually enrolls for such coverage. The reduced rate described in the immediately preceding sentence shall be the contribution rate charged by the Company to similarly situated active employees/dependents, as adjusted from time to time. Employee (or surviving covered dependents) shall complete and return all required forms to the Company and the insurance carriers in order to receive the benefits described in this Section. Employee (or surviving covered dependents) further agrees that she shall promptly notify the Company when an event as described in this paragraph 2(c) of this Agreement has occurred, which terminates Employee’s (or any surviving covered dependent’s) eligibility for continued benefit coverage or coverage at a reduced rate. Such notification shall be directed to: American Electric Power Service Corporation, Human Resources Department, Attn: Payroll Manager, 1 Riverside Plaza, Columbus, OH 43215, 1-888-AEP-BENE (1-888-237-2363.)

3. Other Payments.

(a)Stock Award under LTIP. The Company shall deliver to Employee $500,000 in unrestricted shares of Common Stock of American Electric Power Company, Inc. (the “Shares”) to Employee in accordance with the terms of the American Electric Power System Long-Term Incentive Plan (“LTIP”); with the number of shares to be delivered to be determined by dividing $500,000 by the closing market price on the Termination Date. The delivery of Shares shall be made after the Company determines that Employee has maintained continuous AEP employment through the Termination Date, with delivery to be made to an account set up for Employee’s benefit with a broker/dealer designated by the Company within a reasonable time (generally 3 days) after the Company has made that determination. Fractional Shares may instead be converted to cash or applied as additional income tax withholding at the Company’s option. The Shares and Executive shall remain subject to all applicable legal and regulatory restrictions such as insider trading restrictions and blackout periods. The Company may reduce the number of Shares delivered to Employee to satisfy tax-withholding obligations. This award is subject in all respects to the terms and provisions of the LTIP, all the terms and provisions of which are made a part of and incorporated in this Agreement (as if they were expressly set forth herein). In the event of any
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conflict between the terms of this section of the Agreement and the terms of the LTIP, the terms of the LTIP shall control.

(b)Incentive Compensation. No later than March 15, 2021, Employee will receive a payment, if applicable, under the Company’s Incentive Compensation Plan (“ICP”) for 2020. This payment, if any, will be made at approximately the same time and utilizing the same overall Award Score as the awards for other executive officer participants in the ICP receiving an incentive compensation payment for 2021, without individual discretionary adjustment, and will be calculated based upon the ICP eligible earnings of Employee for 2020, recognizing that the payments described in this Agreement shall not be considered ICP eligible earnings.

4. Consideration. Employee acknowledges that the benefits described in this Agreement are benefits to which Employee would not be entitled but for this Agreement.

5. Release and Waiver of Claims. In consideration of the foregoing benefits, subject to Section 10 of this Agreement (Protected Activity), Employee, on behalf of Employee and Employee’s heirs, executors, administrators, successors, assigns and personal representatives, hereby releases and forever discharges the Company (as defined the first paragraph 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 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, 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 state or local discrimination, fair employment practices, and/or wage and hour laws; for West Virginia employees, those arising under the West Virginia Human Rights Act; those arising under 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 benefits, claims which cannot be waived by law and those payments and benefits enumerated in the Summary of Benefits from Andrew R. Carlin to Employee, a copy of which is attached hereto as Exhibit A. Employee further does not release, discharge or waive any
3

rights to indemnification or other protection that Employee may have under the By-Laws or Resolutions of the Company, the laws of the States of New York and/or Ohio, any indemnification agreement between Employee and the Company, or any insurance coverage maintained by or on behalf of the Company (including but not limited to Director and Officer insurance), nor will the Company take any action, directly or indirectly, to encumber or adversely affect Employee’s rights under any such indemnification arrangement or insurance. Further, the release contained in this Section will not affect any rights granted to Employee, or obligations of the Company, under the terms of this Agreement. 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 prior to execution of this Agreement. Employee further waives any claim Employee may have for reemployment with the Company.

6. Agreement Not to Compete. Employee agrees not to, during the 12 month period following 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 Employee at any time during Employee’s employment with 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 6 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 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 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.

7. 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
4

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.

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. Without intending to limit the scope of the preceding sentence, Employee hereby acknowledges that Section 6.2 of that Executive Severance Plan was amended October 24, 2016 (after the Executive signed the Acknowledgement of Eligibility & Agreement to Comply with Conditions for the Plan) to read as follows (understanding that references to the “Eligible Employee” are references to “Employee”):

“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 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
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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.”

9. No Admission of Liability. Employee understands that the Company believes that Employee has no valid claim against the Company. 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 Employee 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 Employee’s 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 Employee’s right to file a claim with the DOL pursuant to Section 211 of the Energy Reorganization Act, but Employee expressly waives Employee’s 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.

(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
6

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. Enforcement of Certain Covenants. It is recognized that damages in the event of breach of the covenants set forth in sections 5 (Non-competition) and 7 (form Article VI of the Executive Severance Plan) by Employee would be difficult, if not impossible, to ascertain, and it is therefore agreed that the Company, in addition to and without limiting any other remedy or right that the Company may have, shall have the right to seek an injunction or other equitable relief in any court of competent jurisdiction, enjoining any such breach. The existence of this right shall not preclude the Company from pursuing any other rights or remedies at law or in equity, which the Company may have.

12. Return of Property. All Company computers, files, access keys, desk keys, ID badges and credit cards, and such other property of the Company as the Company may reasonably request, in Employee’s possession must be returned no later than the Termination Date, or prior thereto if requested by the Company. Except to the extent inconsistent with Company policy in effect as of the Termination Date and upon the Request made by the employee at least 3 business days prior to the Termination Date:

(i) The Company shall assign to Employee the telephone number then in effect with respect to the cell phone device issued to Employee as of the Termination Date; and

(ii) Once the Company is satisfied that it is able to remove to the Company’s satisfaction all Company confidential information to which the device may have had access:

(A) the Company shall transfer to Employee ownership of the cell phone assigned to Employee as of the Termination Date; and

(B) The Company shall give Employee the opportunity to purchase the tablet computer assigned to Employee as of the Termination Date at a price based on the Company’s estimate of the then market value of that device.

13. 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.

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14. Applicable Law . This Agreement shall be governed and interpreted in accordance with the laws of Ohio and applicable federal law.

15. 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.

16. 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 ADVISED THAT THE TOLL FREE NUMBER OF THE WEST VIRGINIA STATE BAR ASSOCIATION IS 1-800-642-3617.

17. 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.	
			
/s/ Lana L. Hillebrand		By /s/ Nick K. Akins	
Lana L. Hillebrand		     Nick K. Akins	
			
Date 10/21/20		Date 10/22/20	
8

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-Q 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:   October 22, 2020	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-Q 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: October 22, 2020	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-Q 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:   October 22, 2020	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-Q 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:   October 22, 2020	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-Q 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:   October 22, 2020	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-Q 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:   October 22, 2020	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-Q 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:   October 22, 2020	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-Q 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:   October 22, 2020	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, Brian X. Tierney, certify that:

1.I have reviewed this report on Form 10-Q 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:   October 22, 2020	By:		/s/ Brian X. Tierney	
			Brian X. Tierney	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.I have reviewed this report on Form 10-Q 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: October 22, 2020	By:		/s/ Brian X. Tierney	
			Brian X. Tierney	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.I have reviewed this report on Form 10-Q 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:   October 22, 2020	By:		/s/ Brian X. Tierney	
			Brian X. Tierney	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.I have reviewed this report on Form 10-Q 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:   October 22, 2020	By:		/s/ Brian X. Tierney	
			Brian X. Tierney	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.I have reviewed this report on Form 10-Q 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:   October 22, 2020	By:		/s/ Brian X. Tierney	
			Brian X. Tierney	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.I have reviewed this report on Form 10-Q 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:   October 22, 2020	By:		/s/ Brian X. Tierney	
			Brian X. Tierney	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.I have reviewed this report on Form 10-Q 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:   October 22, 2020	By:		/s/ Brian X. Tierney	
			Brian X. Tierney	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.I have reviewed this report on Form 10-Q 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:   October 22, 2020	By:		/s/ Brian X. Tierney	
			Brian X. Tierney	
			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 Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 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

October 22, 2020

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 Quarterly Report of AEP Transmission Company, LLC (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 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

October 22, 2020

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 Quarterly Report of AEP Texas Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 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

October 22, 2020

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 Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 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

October 22, 2020

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 Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 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

October 22, 2020

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 Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 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

October 22, 2020

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 Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 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

October 22, 2020

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 Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 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

October 22, 2020

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 Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, 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/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer

October 22, 2020

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 Quarterly Report of AEP Transmission Company, LLC (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, 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/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer

October 22, 2020

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 Quarterly Report of AEP Texas Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, 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/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer

October 22, 2020

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 Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, 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/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer

October 22, 2020

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 Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, 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/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer

October 22, 2020

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 Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, 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/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer

October 22, 2020

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 Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, 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/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer

October 22, 2020

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 Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, 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/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer

October 22, 2020

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 September 30, 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 **	$	369 		
Number of Mining-related Fatalities	—	

*    References to sections under the Mine Act.
**     DHLC received three non-S&S citations during the third quarter of 2020. Proposed assessments for citations received this quarter totaled $369.

There are currently no legal actions pending before the Federal Mine Safety and Health Review Commission.